Midstream (EQTNP) 10-K2023 FY Annual report

Unless the context otherwise requires, a reference to a "Note" herein refers to the accompanying Notes to the consolidated financial statements contained in Part II, "Item 8. Financial Statements and Supplementary Data" of this Annual Report on Form 10-K and all references to "we," "us," "our" and "the Company" refer to Equitrans Midstream Corporation and its subsidiaries.

Disclosures in this Annual Report on Form 10-K contain certain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act), and Section 27A of the Securities Act of 1933, as amended (the Securities Act). Statements that do not relate strictly to historical or current facts are forward-looking and usually identified by the use of words such as "aim," "anticipate," "approximate," "aspire," "assume," "believe," "budget," "continue," "could," "design," "estimate," "expect," "focused," "forecast," "goal," "guidance," "intend," "may," "objective," "opportunity," "outlook," "plan," "position," "potential," "predict," "project," "pursue," "scheduled," "seek," "should," "strategy," "strive," "target," "view," "will," or "would" and other words of similar meaning in connection with any discussion of future operating or financial matters. Without limiting the generality of the foregoing, forward-looking statements contained in this Annual Report on Form 10-K include the matters discussed in the sections captioned "Developments, Market Trends and Competitive Conditions" in Part I, "Item 1. Business" and "Outlook" in Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations," and the expectations of plans, strategies, objectives, and growth and anticipated financial and operational performance of Equitrans Midstream Corporation (together with its subsidiaries, Equitrans Midstream or the Company), including the following and/or statements with respect thereto, as applicable:

Any forward-looking statement speaks only as of the date on which such statement is made and the Company does not intend to correct or update any forward-looking statement, unless required by securities law, whether as a result of new information, future events or otherwise. As forward-looking statements involve significant risks and uncertainties, caution should be exercised against placing undue reliance on such statements.

Equitrans Midstream is one of the largest natural gas gatherers in the U.S. and holds a significant transmission footprint in the Appalachian Basin. Equitrans Midstream, a Pennsylvania corporation, became an independent, publicly traded company on November 12, 2018 and its common stock trades on the New York Stock Exchange under the symbol "ETRN". The Company provides midstream services to its customers in Pennsylvania, West Virginia and Ohio through its three primary assets: the gathering system, which includes predominantly dry gas gathering systems of high-pressure gathering lines; the transmission system, which includes FERC-regulated interstate pipelines and storage systems; and the water network, which primarily consists of water pipelines, storage and other facilities that support well completion and produced water handling activities.

As of December 31, 2023, the Company provided a majority of its natural gas gathering, transmission and storage services and water services under long-term contracts that generally include firm reservation fee revenues. For the year ended December 31,

2023, approximately 70% of the Company's operating revenues were generated from firm reservation fee revenues. Generally, the Company is focused on utilizing contract structures reflecting long-term firm capacity, MVC or ARC commitments which are intended to provide support to its cash flow profile. The percentage of the Company's operating revenues that are generated by firm reservation fees (as well as the Company's revenue generally) may vary year to year depending on various factors, including customer volumes and the rates realizable under the Company's contracts, including the EQT Global GGA (defined below) which provides for periodic gathering MVC fee declines through January 1, 2028 (with the fees then remaining fixed throughout the remaining term). Additionally, as discussed below, in connection with MVP full in-service the EQT Global GGA provides for more significant potential gathering MVC fee declines in certain contract years.

The Company's operations are focused primarily in southwestern Pennsylvania, northern West Virginia and southeastern Ohio, which are prolific resource development areas in the natural gas shale plays known as the Marcellus and Utica Shales. These regions are also the primary operating areas of EQT, the Company's largest customer, which was one of the largest natural gas producers in the United States based on average daily sales volumes as of December 31, 2023. EQT accounted for approximately 61% of the Company's revenues for the year ended December 31, 2023.

Under the EQT Global GGA, the performance obligation is to provide daily MVC capacity and as such the total consideration is allocated proportionally to the daily MVC over the life of the contract. In periods that the gathering MVC revenue billed will exceed the allocated consideration, the excess will be deferred to the contract liability and recognized in revenue when the performance obligation has been satisfied. While the 3.0 Bcf per day MVC capacity became effective on April 1, 2020, additional daily MVC capacity and the associated gathering MVC fees payable by EQT to the Company as set forth in the EQT Global GGA are conditioned upon the full in-service date of the MVP. The performance obligation, the allocation of the total consideration over the life of the contract and the gathering MVC fees payable by EQT under the contract have been in the past, and in the future could be, affected by changes in the timing of the full in-service date of the MVP.

Under the EQT Global GGA, the gathering MVC fee periodically declines through January 1, 2028 (with the fees then remaining fixed throughout the remaining term). Before January 1, 2026, beginning the first day of the quarter in which the full in-service date of the MVP occurs under the EQT Global GGA, the gathering MVC fees payable by EQT to the Company are subject to more significant potential declines for certain contract years as set forth in the EQT Global GGA, which, prior to EQT's exercise of the EQT Cash Option (defined below), provided for estimated aggregate fee relief of up to approximately $270 million in the first twelve-month period, up to approximately $230 million in the second twelve-month period and up to approximately $35 million in the third twelve-month period. Given that the MVP full in-service date did not occur by January 1, 2022, on July 8, 2022, EQT irrevocably elected under the EQT Global GGA to forgo up to approximately $145 million of the potential gathering MVC fee relief in such first twelve-month period and up to approximately $90 million of the potential gathering MVC fee relief in such second twelve-month period in exchange for a cash payment from the Company to EQT in the amount of approximately $195.8 million (the EQT Cash Option). As a result of EQT exercising the EQT Cash Option (and payment by the Company thereof), the maximum aggregate potential fee relief applicable under the EQT Global GGA in such first twelve-month period and such second twelve-month period was reduced to be up to approximately $125 million and depending on the ultimate in-service date of the MVP, up to approximately $140 million, respectively. The gathering MVC fees and potential declines are subject to certain provisions related to inflation adjustment in accordance with the terms of the EQT Global GGA. Additionally, the EQT Global GGA provides for a fee credit to the gathering rate for certain gathered volumes that also receive separate transmission services under certain transmission contracts.

The following diagram depicts the Company's organizational and ownership structure as of December 31, 2023:

The following is a map of the Company's gathering, transmission and storage and water services operations as of December 31, 2023. Also included are the MVP and MVP Southgate routes, which projects are discussed under "Developments, Market Trends and Competitive Conditions" in Part I, "Item 1. Business" of this Annual Report on Form 10-K.

The Company reports its operations in three segments that reflect its three lines of business: Gathering, Transmission and Water. These segments include all of the Company's operations.

The Company's three business segments correspond to the Company's three primary assets: the gathering system, transmission and storage system and water service system. The following table summarizes the composition of the Company's operating revenues by business segment.

The Company's largest customer, EQT, accounted for approximately 61%, 61% and 59% of the Company's total revenues for the years ended December 31, 2023, 2022 and 2021, respectively.

The Company provides gathering services in two manners: firm service and interruptible service. Firm service contracts are typically long-term and often include firm reservation fees, which are fixed, monthly charges for the guaranteed reservation of pipeline access. Revenues under firm reservation fees also include fixed volumetric charges under MVCs. As of December 31, 2023, the gathering system had total contracted firm reservation capacity (including contracted MVCs) of approximately 7.7 Bcf per day (inclusive of Eureka Midstream contracted capacity), which included contracted firm reservation capacity of approximately 1.8 Bcf per day associated with the Company's high-pressure header pipelines. Including future capacity expected from expansion projects that are not yet fully constructed or not yet fully in-service for which the Company has executed firm contracts, the gathering system had total contracted firm reservation capacity (including contracted MVCs) of approximately 8.8 Bcf per day (inclusive of Eureka Midstream contracted capacity) as of December 31, 2023, which included contracted firm reservation capacity of approximately 1.9 Bcf per day associated with the Company's high-pressure header pipelines. Volumetric-based fees can also be charged under firm contracts for each firm volume gathered, as well as for volumes gathered in excess of the firm contracted volume. Based on total projected contractual revenues, including projected contractual revenues from future capacity expected from expansion projects that are not yet fully constructed or not yet fully in-service for which the Company has executed firm contracts, the Company's firm gathering contracts had a weighted average remaining term of approximately 13 years as of December 31, 2023.

Interruptible service contracts include volumetric-based fees, which are charges for the volume of natural gas gathered and generally do not guarantee access to the pipeline. These contracts can be short- or long-term. To the extent that capacity reserved by customers with firm service contracts is not fully used or excess capacity exists, the gathering system can allocate capacity to interruptible services.

The Company generally does not take title to the natural gas gathered for its customers but retains a percentage of wellhead gas receipts to recover natural gas used to fuel certain of its compressor stations and meet other requirements on the Company's gathering systems.

access to markets in Pennsylvania, West Virginia and Ohio and to the Mid-Atlantic, Northeastern, Midwestern and Gulf Coast markets through interconnect points with major interstate pipelines.

The Company provides transmission and storage services in two manners: firm service and interruptible service. Firm service contracts are typically long-term and often include firm reservation fees, which are fixed, monthly charges for the guaranteed reservation of pipeline and storage capacity. Volumetric-based fees can also be charged under firm contracts for firm volume transported or stored, as well as for volumes transported or stored in excess of the firm contracted volume. As of December 31, 2023, the Company had firm capacity subscribed under firm transmission contracts of approximately 5.8 Bcf per day, which includes future capacity expected from expansion projects that are not yet fully constructed or not yet fully in-service for which the Company has executed firm transmission contracts and excludes approximately 2.6 Bcf per day of firm capacity commitments associated with the MVP and MVP Southgate projects. As of December 31, 2023, the Company had firm storage capacity of approximately 29.8 Bcf subscribed under firm storage contracts. Based on total projected contractual revenues, including projected contractual revenues from future capacity expected from expansion projects that are not yet fully constructed or not yet fully in-service for which the Company has executed firm contracts, the Company's firm transmission and storage contracts had a weighted average remaining term of approximately 12 years as of December 31, 2023.

Interruptible service contracts include volumetric-based fees, which are charges for the volume of natural gas transported or stored and generally do not guarantee access to the pipeline or storage facility. These contracts can be short- or long-term. To the extent that capacity reserved by customers with firm service contracts is not fully used or excess capacity exists, the transmission and storage systems can allocate capacity to interruptible services.

The Company generally does not take title to the natural gas transported or stored for its customers but retains a percentage of gas receipts to recover natural gas used to fuel its compressor stations and meet other requirements of the Company's transmission and storage systems.

buried pipeline and two water storage facilities with 350,000 barrels of capacity, as well as two interconnects with the Company’s existing Pennsylvania fresh water systems and provides services to producers in southwestern Pennsylvania. The Company plans to continue to expand its mixed water system in 2024, including the completion of a pipeline to serve a producer in West Virginia and a water pipeline, scheduled to be completed in the first quarter of 2025, to interconnect with the same producer's Pennsylvania mixed water network.

The Company's strategically located and integrated assets overlay core acreage in the Appalachian Basin. The location of the Company's assets allows its producer customers to access major demand markets in the U.S. The Company is one of the largest natural gas gatherers in the U.S., and its largest customer, EQT, was one of the largest natural gas producers in the U.S. based on average daily sales volumes as of December 31, 2023 and EQT's public senior debt had investment grade credit ratings from Standard & Poor's Global Ratings (S&P), Fitch Ratings (Fitch) and Moody's Investors Service (Moody's) as of that date. For the year ended December 31, 2023, approximately 70% of the Company's operating revenues were generated from firm reservation fee revenues. Generally, the Company is focused on utilizing contract structures reflecting long-term firm capacity, MVC or ARC commitments which are intended to provide support to its cash flow profile. The percentage of the Company's operating revenues that are generated by firm reservation fees (as well as the Company's revenues generally) may vary year to year depending on various factors, including customer volumes and the rates realizable under the Company's contracts, including the EQT Global GGA which provides for periodic gathering MVC fee declines through January 1, 2028 (with the fee then remaining fixed throughout the remaining term). Additionally, as discussed above under "Overview of the Company and Operations" in Part 1, "Item 1. Business" of this Annual Report on Form 10-K, in connection with MVP full in-service the EQT Global GGA provides for more significant potential gathering MVC fee declines in certain contract years.

See "Sustainability and Corporate Responsibility" in Part II, "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations" of this Annual Report on Form 10-K for a discussion of the Company's continued focus on sustainability matters which the Company believes will help to distinctively position the Company and create value.

Competition for natural gas transmission and storage is primarily based on rates, customer commitment levels, timing, performance, commercial terms, reliability, service levels, location, reputation and fuel efficiencies. The Company's principal competitors in its transmission and storage market include companies that own major natural gas pipelines in the Marcellus and Utica Shales. In addition, the Company competes with companies that are building high-pressure gathering facilities that are able to transport natural gas to interstate pipelines without being subject to FERC jurisdiction. Major natural gas transmission companies that compete with the Company also have storage facilities connected to their transmission systems that compete with certain of the Company's storage facilities.

Key competition for water services includes natural gas producers that develop their own water distribution systems in lieu of employing the Company's water services assets and other natural gas midstream companies that offer water services. The Company's ability to attract customers to its water service business depends on its ability to evaluate and select suitable projects and to consummate transactions in a highly competitive environment.

Further, natural gas as a fuel competes with other forms of energy available to end-users, including coal, certain liquid fuels and, increasingly, renewable and alternative energy. Demand for renewable and alternative energy is increasing generally with changes in consumer preferences, governmental clean energy policies, and as renewable and alternative energy becomes more cost competitive with traditional fuels (including by technological advancement, legislation or government subsidies, as well as traditional supply and demand dynamics) and more widely available. Continued increases in the demand for renewable and alternative energy at the expense of natural gas (or increases in the demand for other sources of energy, particularly if prices for natural gas are elevated relative to other forms of energy as fuel) could lead to a reduction in demand for natural gas gathering, transmission and storage, and water services.

The FERC regulates the rates and charges for transmission and storage in interstate commerce. Unless market-based rates have been approved by the FERC, the maximum applicable recourse rates and terms and conditions for service are set forth in the pipeline's FERC-approved tariff. Generally, the maximum filed recourse rates for interstate pipelines are based on the cost of providing service, including the recovery of a return on the pipeline's actual and prudent historical investment costs. Key determinants in the ratemaking process include the depreciated capital costs of the facilities, the costs of providing service, the allowed rate of return and income tax allowance, as well as volume throughput and contractual capacity commitment assumptions.

Interstate pipelines may not charge rates or impose terms and conditions of service that, upon review by the FERC, are found to be unjust or unreasonable, unduly discriminatory or preferential. Rate design and the allocation of costs also can affect a pipeline's profitability. While the ratemaking process establishes the maximum rate that can be charged, interstate pipelines such as the Company's transmission and storage system are permitted to discount their firm and interruptible rates without further FERC authorization down to a specified minimum level, provided they do not unduly discriminate. In addition, pipelines are allowed to negotiate different rates with their customers, under certain circumstances. Changes to rates or terms and conditions of service, and contracts can be proposed by a pipeline company under Section 4 of the NGA, or the existing interstate transmission and storage rates, terms and conditions of service and/or contracts may be challenged by a complaint filed by interested persons including customers, state agencies or the FERC under Section 5 of the NGA. Rate increases proposed by a pipeline may be allowed to become effective subject to refund and/or a period of suspension, while rates or terms and conditions of service that are the subject of a complaint under Section 5 of the NGA are subject to prospective change by the FERC. Rate increases proposed by a regulated interstate pipeline may be challenged and such increases may ultimately be rejected by the FERC.

The Company's interstate pipeline may also use negotiated rates that could involve rates above or below the recourse rate or rates that are subject to a different rate structure than the rates specified in the Company's interstate pipeline tariffs, provided that the affected customers are willing to agree to such rates and that the FERC has approved the negotiated rate agreement. A prerequisite for allowing the negotiated rates is that negotiated rate customers must have had the option to take service under the pipeline's recourse rates. As of December 31, 2023, approximately 97% of the system's contracted firm transmission capacity was subscribed by customers under negotiated rate agreements under its tariff. Some negotiated rate transactions are designed to fix the negotiated rate for the term of the firm transportation agreement and the fixed rate is generally not subject to adjustment for increased or decreased costs occurring during the contract term.

The FERC’s regulations also extend to the terms and conditions set forth in agreements for transmission and storage services executed between interstate pipelines and their customers. These service agreements are required to conform, in all material respects, with the form of service agreements set forth in the pipeline's FERC-approved tariff. Non-conforming agreements must be filed with and accepted by the FERC. In the event that the FERC finds that an agreement is materially non-conforming, in whole or in part, it could reject, or require the Company to seek modification of, the agreement, or alternatively require the Company to modify its tariff so that the non-conforming provisions are generally available to all customers or class of customers.

The FERC’s jurisdiction also extends to the certification and construction of new interstate transmission and storage facilities, including, but not limited to, acquisitions, facility replacements and upgrades, expansions, and abandonment of facilities and services. Prior to commencing construction of new or existing interstate transmission and storage facilities, an interstate pipeline must obtain (except in certain circumstances, such as where the activity is permitted under the FERC’s regulations or is authorized under the operator’s existing blanket certificate issued by the FERC) a certificate authorizing the construction, or file to amend its existing certificate, from the FERC.

On April 19, 2018, the FERC issued a Notice of Inquiry (2018 Notice of Inquiry) seeking information regarding whether, and if so how, it should revise its approach under its currently effective policy statement on the certification of new natural gas transportation facilities (Certificate Policy Statement). The formal comment period in this proceeding closed on June 25, 2018. On February 18, 2021, the FERC issued another Notice of Inquiry in the same proceeding that modified and expanded the inquiry and renewed its request for public comment (together with the 2018 Notice of Inquiry, the Certificate Policy Statement NOI). The formal comment period closed May 26, 2021. On February 18, 2022, the FERC issued an Updated Certificate Policy Statement. On February 18, 2022, the FERC issued an interim GHG policy. On March 24, 2022, the FERC issued an order suspending the effectiveness of the Updated Certificate Policy Statement and the interim GHG policy and has taken no further action to date.

In 2024, there is a possibility that the U.S. Congress could pass legislation revising the NGA or other statutes that may impact the Company's existing facilities and operations or the ability to construct new facilities. Potential areas of revision include, but are not limited to, (i) amending Section 5 of the NGA to allow the FERC to require a pipeline to make refunds from the date that a NGA Section 5 complaint was filed with the FERC if rates are later found to be unjust and unreasonable; (ii) amending

Section 7 of the NGA affecting the ability of companies to exercise eminent domain; and (iii) amending Section 19(b) of the NGA to provide the FERC additional time to act on requests for rehearing.

The FERC had four commissioners in 2023. However, Commissioner James Danly left the FERC at the end of 2023. On February 9, 2024, President Biden named Willie Phillips Chairman of the FERC. Commissioner Allison Clements’s term expires on June 30, 2024, and she has indicated that she will not seek another term, leaving the possibility that the FERC could be without a quorum of three members in 2024. If Congress does not confirm Commissioner Clements's replacement prior to expiration of her term, Commissioner Clements may remain in her position until the end of the current the U.S. Congress in January 2025. As of the filing of this Annual Report on Form 10-K, President Biden has not yet nominated new commissioners.

The Company believes that its high-pressure gathering systems meet the traditional tests the FERC has used to establish a pipeline's status as an exempt gatherer not subject to regulation as a jurisdictional natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is often the subject of litigation in the industry, so the classification and regulation of these systems are subject to change based on future determinations by the FERC, the courts or the U.S. Congress.

Notwithstanding the investigatory and preventative maintenance costs incurred in the Company's performance of customary pipeline and storage management activities, the Company may incur significant additional expenses if anomalous pipeline or storage conditions are discovered or more stringent safety requirements are implemented. For example, in April 2016, the PHMSA published a notice of proposed rulemaking addressing several integrity management topics and proposing new requirements to address safety issues for natural gas transmission and gathering lines, along with certain storage facilities (the Mega Rule). The PHMSA intended the Mega Rule to strengthen existing integrity management requirements, expand assessment and repair requirements to pipelines in areas with medium population densities, and extend regulatory requirements to onshore gas gathering lines that are currently exempt. Part I of the Mega Rule was promulgated on October 1, 2019, with an effective date of July 1, 2020 (see discussion below). Part II was promulgated on November 15, 2021, with an effective date of May 16, 2022 (see discussion below). Finally, Part III of the Mega Rule was promulgated on August 24, 2022, with an effective date of May 24, 2023 (see discussion below).

Further, in June 2016, then-President Obama signed the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (the 2016 Pipeline Safety Act), extending the PHMSA's statutory mandate under prior legislation through 2019. In

addition, the 2016 Pipeline Safety Act empowered the PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing and also required the PHMSA to develop new safety standards for natural gas storage facilities by June 2018. Pursuant to those provisions of the 2016 Pipeline Safety Act, the PHMSA issued a final rule effective December 2, 2019 that expanded the agency's authority to impose emergency restrictions, prohibitions and safety measures and issued a final rule effective March 13, 2020 that strengthened the rules related to underground natural gas storage facilities, including well integrity, wellbore tubing and casing integrity

Following the October 2016 Interim Final Rule, the PHMSA also published five final rules on pipeline safety applicable to the Company: "Enhanced Emergency Order Procedures;" "Safety of Gas Transmission Pipelines: Maximum Allowable Operating Pressure Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments" (also known as the Mega Rule Part I); and "Safety of Gas Gathering Pipelines: Extension of Reporting Requirements, Regulation of Large, High-Pressure Lines, and Other Related Amendments" (also known as the Mega Rule Part II); and "Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments" (also known as the Mega Rule Part III); and “Pipeline Safety: Requirement of Valve Installation and Minimum Rupture Detection Standards” (the valve rule). The Enhanced Emergency Order Procedures rule, which became effective on December 2, 2019, implements an existing statutory authorization for the PHMSA to issue emergency orders related to pipeline safety if an unsafe condition or practice, or a combination of unsafe conditions and practices, constitutes, or is causing an imminent hazard. Mega Rule Part I, which went into effect on July 1, 2020, requires operators of certain gas transmission pipelines that have been tested or that have inadequate records to determine the material strength of their lines by reconfirming the Maximum Allowable Operating Pressure (MAOP), and establishes a new Moderate Consequence Area for determining regulatory requirements for gas transmission pipeline segments outside of high consequence areas. The rule also establishes new requirements for conducting baseline assessments, incorporates into the regulations industry standards and guidelines regarding design, construction and in-line inspections (ILI), and new requirements for data integration and risk analysis in integrity management programs, including seismicity, manufacturing and construction defects, and crack and crack-like defects, and includes several requirements that allow operators to notify the PHMSA of proposed alternative approaches to achieving the objectives of the minimum safety standards. Mega Rule Part II, which was finalized on November 15, 2021 and went into effect on May 16, 2022, extends existing design, operational and maintenance, and reporting requirements to onshore natural gas gathering pipelines in rural areas. The rule requires operators of onshore gas gathering pipelines to report incidents and file annual reports (with the first annual reports submitted in Spring 2023), and creates new safety requirements that vary based on pipeline diameter and potential consequences of a failure. Mega Rule Part III, which was finalized on August 24, 2022, went into effect on May 24, 2023. The rule requires operators of certain transmission pipelines to assess their integrity management practices, and comply with enhanced corrosion control and mitigation timelines. It also establishes new requirements for pipeline inspections following an extreme weather event or natural disaster, and provides enhanced guidance for pipeline repairs. The valve rule requires the installation of remote operated rupture mitigation valves on new or entirely replaced transmission and storage lines when valves are installed to meet valve spacing requirements. In addition the valve rule includes requirements for operator actions to be taken when notified of a potential rupture that include notifying emergency response agencies and closing valves within a specified timeframe. In 2023, the Company did not incur material compliance costs in connection with complying with the PHMSA rules applicable to the Company. However, as discussed below, the Company does expect certain compliance costs to increase in the near future, and the Company continues to assess the impact of compliance with these rules which could materially impact its future costs of operations and revenue from operations. For example, Mega Rule Part I requires MAOP reconfirmation of certain previously untested transmission pipeline segments, which are commonly referred to as ‘‘grandfathered’’ pipelines. The Company’s grandfathered pipeline MAOP reconfirmation efforts, which the Company has initiated, may result in unanticipated testing and/or replacement costs. When reconfirming MAOP on certain of the Company’s grandfathered pipeline segments the Company may be required to remove portions of pipelines for testing, shut in certain pipelines, and/or may face significant operational or technical challenges when performing either a pressure test or an ILI examination, which could result in substantial costs related thereto, or to repairs, remediation, or replacing existing pipelines, and/or other mitigating actions that may be determined to be necessary as a result of the tests, as well as lost cash flows resulting from shutting down the Company's pipelines during the pendency of any such actions, which could be material to capital expenditures, earnings and the Company's competitive position. Additionally, ensuring complete compliance with the applicable Mega Rule compliance deadlines may cause the Company to incur significant additional expenses if anomalous pipeline conditions are discovered.

States are generally preempted by federal law in the area of pipeline safety, but state agencies may qualify to assume responsibility for enforcing federal regulations over intrastate pipelines. They may also promulgate additive pipeline safety regulations provided that the state standards are at least as stringent as the federal standards. Although many of the Company's natural gas facilities fall within a class that is not subject to integrity management requirements, the Company may incur significant costs and liabilities associated with repair, remediation, preventive or mitigation measures associated with its non-exempt transmission pipelines. The costs, if any, for repair, remediation, preventive or mitigating actions that may be

determined to be necessary as a result of the testing program, as well as lost cash flows resulting from shutting down the Company's pipelines during the pendency of any such actions, could be material to capital expenditures, earnings and the Company's competitive position.

Should the Company fail to comply with U.S. DOT regulations adopted under authority granted to the PHMSA, it could be subject to penalties and fines. The PHMSA has the statutory authority to impose civil penalties for pipeline safety violations up to a maximum of approximately $266,000 per day for each violation and approximately $2.6 million for a related series of violations. This maximum penalty authority established by statute will continue to be adjusted periodically to account for inflation. In addition, the Company could be required to make additional, unforeseen maintenance capital expenditures in the future for its regulatory compliance initiatives. Additionally, the adoption of new laws and regulations, such as the Mega Rule discussed above, could result in significant added costs or delays to in service or the termination of projects, which could have a material adverse effect on the Company in the future.

On December 27, 2020, then-President Trump signed the "Protecting our Infrastructure of Pipelines and Enhancing Safety (PIPES Act) of 2020," which reauthorized the federal pipeline safety program that expired in 2019. The PIPES Act identifies areas where the U.S. Congress believed additional oversight, research, or regulations was needed. The PIPES Act includes new mandates for the PHMSA to require operators to update, as needed, their emergency response plans and operating and maintenance plans. The PIPES Act also requires operators to manage records and update, as necessary, their existing district regulator stations to eliminate a common mode of failure. The PHMSA will also require that leak detection and repair programs consider the environment, the use of advance lead detection practices and technologies, and that operators be able to locate and categorize all leaks that are hazardous to human safety, the environment, or that can become hazardous. The Company has not incurred and does not anticipate incurring material capital expenditures in connection with complying with the PIPES Act.

On November 30, 2022, the TSA issued an advanced notice of proposed rulemaking seeking comment on how to strengthen cybersecurity and resiliency in, among other areas, the pipeline sector. The comment period ended in February 2023. As of the filing of this Annual Report on Form 10-K, it is not clear if or when the TSA will issue a notice of proposed rulemaking. Should any regulations be promulgated, the Company will likely be covered by them, but it is not possible as of the filing of this Annual Report on Form 10-K to predict the ultimate impact such regulations may have on the Company's business or operations.

In March 2022, President Biden signed into law the Cyber Incident Reporting for Critical Infrastructure Act of 2022 (CIRCIA). CIRCIA directs the U.S. Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) to promulgate regulations requiring certain entities to report to CISA certain cyber incidents. The Company expects that it will be subject to such regulations after they are promulgated and continues to monitor regulatory developments to ensure future compliance and assess the impact the compliance with these rules on its future costs of operations. As of the filing of this Annual Report on Form 10-K, it is not possible to predict the ultimate impact such regulations may have on the Company’s business or operations.

The regulatory environment surrounding cybersecurity continues to evolve in ways that are frequently difficult to predict. We have been required and may further be required to expend additional resources as a result of current or new laws, regulations, directives or other requirements, or changes in the interpretation or enforcement practices thereof, related to cybersecurity, which could result in material compliance costs. Additionally, we may become subject to multiple incident reporting requirements and other cybersecurity obligations that could overlap or conflict with each other, resulting an increased risk of non-compliance or in different responses to the same incident. Any failure to remain in compliance with laws or regulations governing cybersecurity, including the requirements contained in the Company’s CIP, may result in penalties, fines, enforcement actions, or mandated changes in our practices, which may have a material adverse effect on our business and operations.

In addition, the Company's operations and construction activities may be subject to county and local ordinances that restrict the time, place or manner in which those operations and activities may be conducted.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of investigatory and remedial obligations and the issuance of orders enjoining future operations or imposing additional compliance requirements. Also, certain environmental statutes impose strict, and in some cases joint and several, liability for the cleanup and restoration of sites where hydrocarbons or wastes have been disposed or otherwise released regardless of the fault of the current site owner or operator. Consequently, the Company may be subject to environmental liability at its currently owned or operated facilities for conditions caused by others prior to the Company's involvement.

The Company has implemented programs and policies designed to keep its pipelines and other facilities in compliance with existing environmental laws and regulations, and the Company does not believe that the cost of its compliance with such legal requirements will have a material adverse effect on its business, financial condition, results of operations, liquidity or ability to pay dividends to its shareholders. Nonetheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and it is generally expected that such trend will likely increase under the Biden Administration. Thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be significantly in excess of the amounts the Company anticipates as of the filing of this Annual Report on Form 10-K. For example, the Biden Administration has announced that it will be reviewing the National Ambient Air Quality Standards (NAAQS) for ozone and may make these standards more stringent. This could result in the areas in which the Company operates being designated as nonattainment areas. States that contain any areas designated as nonattainment areas will be required to develop implementation plans demonstrating how the areas will attain the applicable standard within a prescribed period of time. These plans may require the installation of

additional equipment to control emissions. The EPA did not make the ozone NAAQS more stringent when it reviewed them in 2020, but the Biden Administration has announced that it will be commencing a review of these NAAQS. In addition, in December 2023, the EPA issued a final rule that makes more stringent the volatile organic compound (VOC) and methane emissions limits on certain new and modified equipment in the oil and gas source category, including certain types of compressors and pneumatic pumps. The final rule also extends these requirements to existing sources for the first time. Some states are also enacting methane reduction programs. For example, Pennsylvania has a methane reduction framework for the oil and gas industry that will result in an existing source VOC regulation with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines.

Compliance with these or other new regulations could, among other things, require installation of new emission controls on some of the Company's equipment, result in longer permitting timelines, and significantly increase the Company's capital expenditures and operating costs, which could adversely affect the Company's business. The Company continuously attempts to anticipate future regulatory requirements that might be imposed and works to remain in compliance with changing environmental laws and regulations.

The following is a discussion of several of the material environmental laws and regulations, as amended from time to time, that relate to the Company's business.

In the ordinary course of the Company's operations, the Company generates wastes constituting solid wastes, and in some instances hazardous wastes, which are subject to the requirements of the Resource Conservation and Recovery Act (RCRA) and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. While certain petroleum production wastes are excluded from RCRA's hazardous waste regulations, it is possible that these wastes will in the future be designated as "hazardous wastes" and be subject to more rigorous and costly disposal requirements, which could have a material adverse effect on the Company's maintenance capital expenditures and operating expenses.

The Company owns, leases or operates properties where petroleum hydrocarbons are being or have been handled for many years. The Company has generally utilized operating and disposal practices that are standard in the industry at the time, although petroleum hydrocarbons or other wastes may have been disposed of or released on or under the properties owned, leased or operated by the Company, or on or under the other locations where these petroleum hydrocarbons and wastes have been transported for treatment or disposal. Petroleum hydrocarbons or other wastes may have been disposed or released on certain of these properties by third parties that previously operated, owned or leased these properties and whose treatment and disposal or release of petroleum hydrocarbons and other wastes were not under the Company's control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination.

criminal enforcement actions. The Company may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining permits and approvals for air emissions.

These types of capital expenditures could also be required in areas that are nonattainment for the ozone NAAQS depending on the design of the relevant state’s implementation plan to meet the air quality standards. The EPA did not make the ozone NAAQS more stringent when it reviewed them in 2020, and although the Biden Administration initially indicated that it would reconsider that decision, the EPA announced in August 2023 that it would cease its reconsideration and begin an entirely new review of the ozone NAAQS that would need to be completed by 2025 under the federal Clean Air Act. As of the filing of this Annual Report on Form 10-K, it is not clear when the EPA will issue a notice of proposed rulemaking. If the ozone NAAQS are made more stringent, this could result in additional nonattainment areas being designated, which could in turn result in the Company being required to install additional pollution control equipment. Moreover, with regard to the 2015 ozone NAAQS, the EPA released a final rule in May 2023 called the Good Neighbor Plan that imposes a federal implementation plan in 23 states to address air pollution from those states that is contributing to downwind nonattainment of the 2015 ozone NAAQS in other states. The final rule establishes limitations on emissions of nitrogen oxides for certain industrial stationary sources in 23 states, including states in which the Company operates. The rule has been stayed in 12 states including West Virginia by seven different federal courts of appeals because the underlying disapproval of those states’ state implementation plans has been found likely to have been unlawful. The Good Neighbor Plan remains in effect in the remaining 11 states including Ohio, Pennsylvania and Virginia. The final Good Neighbor Plan has been challenged in various courts of appeals, including the D.C. Circuit. The D.C. Circuit denied a motion to stay the rule in September 2023, and some of the parties filed emergency stay applications with the U.S. Supreme Court in October 2023. The U.S. Supreme Court has scheduled oral argument on the emergency stay applications for February 21, 2024. As of the filing of this Annual Report on Form 10-K, it is not clear how the U.S. Supreme Court will rule on the emergency stay application or how the other courts of appeals will rule on the challenges to the underlying disapproval of some states' implementation plans and on the Good Neighbor Plan itself. If the Good Neighbor Plan withstands these judicial challenges and remains in place in states in which the Company operates, the Company will be required to install additional pollution control equipment on certain of its assets, but the Company does not anticipate that compliance with the Good Neighbor Plan will have a material effect on the Company’s capital expenditures, earnings and competitive position.

In August 2023, an EPA issued final rule removing the “emergency” affirmative defense provision from the EPA’s Title V permit program regulations became effective. The EPA removed this provision from the permitting program because the agency found that these provisions conflicted with its current interpretation of the enforcement structure of the Clean Air Act. The EPA has directed states with similar emergency affirmative defense provisions in their Title V permitting programs to revise permits contains those provisions during permit renewals. The final rule has been challenged in the D.C. Circuit, but, as of the filing of this Annual Report on Form 10-K, is in abeyance awaiting a decision in a separate D.C. Circuit case involving a different EPA rule that may have relevance to the challenge to the emergency defense rule. Although the EPA has stated that it “may” use its “case-by-case” enforcement discretion to determine whether to initiate enforcement as appropriate, this rule removes the automatic defense the Company could claim in an emergency situation and may make it more difficult to avoid liability for Title V permit violations.

Future compliance with these requirements may require modifications to certain of the Company's operations, including the installation of new equipment to control emissions from the Company's compressors, that could result in significant costs, including increased capital expenditures and operating costs, and could adversely affect the Company's business.

Legislative and regulatory measures to address climate change and GHG emissions are in various phases of discussion or implementation and are a major focus of the Biden Administration. On January 27, 2021, President Biden signed an executive

order on "Tackling the Climate Crisis at Home and Abroad." This executive order contains sweeping direction to the executive branch to address climate issues. As discussed further below, the construction of interstate natural gas transportation pipelines pursuant to the NGA requires authorization from the FERC, and FERC actions are subject to review under NEPA. NEPA requires federal agencies, such as the FERC, to evaluate major federal actions having the potential to significantly affect the environment. On January 9, 2023, the White House Council on Environmental Quality published new interim guidance entitled “National Environmental Policy Act Guidance on Consideration of Greenhouse Gas Emissions and Climate Change.” Generally, the interim guidance calls for increased scrutiny of the GHG effects of proposed federal action, including requiring agencies to quantify the proposed action’s GHG emissions and relevant climate impacts. The interim guidance and increased review of the GHG impacts of federal action has the potential to significantly delay or limit, and significantly increase the cost of, development of midstream infrastructure. The EPA announced its Climate Enforcement and Compliance Strategy in September 2023, which directs all enforcement and compliance programs in the EPA to address climate change, wherever appropriate, in every matter within their jurisdiction. The Compliance Strategy also directs the EPA to prioritize enforcement and compliance actions to mitigate climate change and to include climate adaptation and resilience requirements whenever appropriate.

The EPA regulates GHG emissions from new and modified facilities that are potential major sources of criteria pollutants under the Clean Air Act's Prevention of Significant Deterioration and Title V programs and has adopted regulations that require, among other things, preconstruction and operating permits for certain large stationary sources and the monitoring and reporting of GHGs from certain onshore oil and natural gas production sources on an annual basis.

Since May 2016, the EPA has regulated methane and VOCs from the oil and gas sector through its new source performance standard program under the Clean Air Act. These initial rules (Subpart OOOOa) impose methane and VOC emissions limits on certain types of new and modified compressors and pneumatic pumps. In December 2023, the EPA issued a final rule, which as of the filing of this Annual Report on Form 10-K has not yet been published in the Federal Register, that does three things: (i) modifies Subpart OOOOa to, among other things, increase fugitive emissions monitoring frequency; (ii) promulgates a new Subpart OOOOb that imposes more stringent requirements on new and modified oil and gas sources that commence construction or modification on or after December 6, 2022; and (iii) promulgates an emissions guideline (a new Subpart OOOOc) that provides direction to the states to regulate VOC and methane emissions from existing sources in the sector for the first time. The Subpart OOOOc directs states to regulate existing sources in largely the same manner in which new and modified sources are regulated under Subpart OOOOb. It is expected that some parties may challenge the final rule once it is published in the Federal Register. It is also expected that some parties may file petitions for reconsideration asking the EPA to reexamine certain parts of the final rule. If those challenges are filed and the rule withstands judicial review, or if the EPA decides against any changes to the final rule in response to petitions for reconsideration, the Company will be required to incur certain capital expenditures for air pollution control equipment, increased fugitive emissions monitoring, and other requirements that could result in significant costs and could adversely affect the Company's business. In addition, the Pennsylvania Environmental Quality Board has promulgated regulations that require conventional oil and natural gas sources of volatile organic compounds and methane to meet reasonably available control technology standards to control these emissions, which could result in significant costs that could adversely affect the Company’s business.

In August 2022, the Inflation Reduction Act (IRA) was enacted. Among other provisions, the IRA includes a methane fee that is imposed on certain types of facilities, including certain ones owned and/or operated by the Company. The IRA exempts from the methane fee those facilities that are subject to the EPA’s final methane rule (Subparts OOOOb and OOOOc discussed above), provided that the rule results in emission reductions that are at least equivalent to those that would be achieved under the November 2021 proposed rule (which is the case for new and modified sources and will be the case for existing sources unless a state is able to justify a lesser standard based on the Clean Air Act’s “remaining useful life and other factors” provision). The EPA published a proposed rule in the Federal Register in January 2024. The proposed rule makes clear that the EPA does not think the exemption for existing sources that are subject to Subpart OOOOc would be available until state plans implementing OOOOc are approved and in effect in all states with sources subject to Subpart OOOOc. If the EPA finalizes this interpretation of the IRA’s exemption, the methane fee could have a material effect on the Company until all states have finalized and had their plans approved by the EPA. Under the IRA, the Company could be liable for methane emissions from applicable facilities that are above 25,000 metric tons of carbon dioxide equivalent. These fees are written into the IRA and are: (1) $900 per ton for any tons over the threshold that are reported for calendar year 2024; (2) $1,200 per ton for any tons over the threshold that are reported for calendar year 2025; and (3) $1,500 per ton for any tons over the threshold that are reported for calendar year 2026 and each year thereafter. Even once all the states have approved state plans to implement Subpart OOOOc, it is possible that the Company could have operations in a state that implements less stringent emissions standards than the final Subpart OOOOc emissions guideline, in which case the exemption would not be available for applicable facilities in that state.

The IRA also directed the EPA to amend Subpart W of the Greenhouse Gas Reporting Rule (which governs GHG emissions by the oil and gas sector). The EPA issued a proposed rule amending Subpart W in August 2023. Depending on how the Subpart OOOOc of the EPA’s final rule and the Subpart W of the Greenhouse Gas Reporting Rule are finalized, there is a potential for

significant impacts on calculation of the Company’s IRA methane fee. In May 2023, the EPA proposed revised new source performance standards and an emissions guideline for certain new, modified, reconstructed, and existing natural gas-fired electric generating units. If finalized, this rule could have an impact on the demand for natural gas from the U.S. power sector, which could have an adverse effect on the demand for the Company’s business. State programs regulating GHG emissions from power plants, such as the Regional Greenhouse Gas Initiative (RGGI), can also have the effect on the Company of reducing demand for natural gas by power plants. RGGI was found, however, to be unconstitutional in Pennsylvania in November 2023, but this decision is being appealed. Virginia also withdrew from the RGGI program effective January 1, 2024, but as of the filing of this Annual Report on Form 10-K, the decision has not yet been challenged in court.

California enacted two climate-related disclosure laws called the Climate Corporate Data Accountability Act (CCDAA) and the Climate-Related Financial Risk Act (CRFRA) on October 7, 2023. These laws may apply to the Company if we are considered to be “doing business in California” under the CCDAA and the CRFRA. Under the CCDAA, we may be required to quantify and disclose certain GHG emissions data in accordance with the GHG Protocol, a standard developed by the World Resources Institute and the World Business Council for Sustainable Development beginning in 2026 (with the reporting of 2025 emissions data). These reports must be independently audited by a third-party assurance provider. The CRFRA may require us to prepare and submit a biennial report in accord with the framework of the Final Report and Recommendations of the Task Force on Climate-related Financial Disclosures disclosing the company’s climate-related financial risk, and the measures it has adopted to reduce and adapt to climate-related financial risk, with the first report due on January 1, 2026. These financial risk reports must be made available to the public on our website by the applicable compliance dates. There are annual fees associated with both the CCDAA and the CRFRA as well. The CCDAA and the CRFRA may cause us to incur additional (and potentially accelerate) compliance and reporting costs, certain of which could be material, including related to monitoring, collecting, analyzing and reporting new metrics and implementing systems and procuring additional necessary attestation. As of the filing of this Annual Report on Form 10-K, the California Air Resources Board has not yet issued proposed regulations to implement these two climate disclosure laws. Similarly, on March 21, 2022, the SEC released proposed rule changes that would require new climate-related disclosure in SEC filings, including certain climate-related metrics and GHG emissions. The SEC proposal, which as of the filing of this Annual Report on Form 10-K has not been finalized, would also require disclosure of our certain GHG emissions, further increasing our compliance and reporting costs. Such costs may adversely affect our future business, financial condition, results of operations, and liquidity.

The U.S. Congress, along with federal and state agencies, has also considered other measures to reduce the emissions of GHGs. Legislation or regulation that imposes a carbon tax on carbon emissions or that restricts those emissions could increase the Company's cost of environmental compliance through the Company's incurrence of increased non-income taxes or by requiring the Company to install new equipment to reduce emissions from larger facilities and/or, depending on any future legislation, purchase emission allowances. The effect of climate change legislation or regulation on the Company's business is uncertain as of the filing of this Annual Report on Form 10-K. If the Company incurs additional costs to comply with such legislation or regulations, it may not be able to pass on the higher costs to its customers or recover all the costs related to complying with such requirements and any such recovery may depend on events beyond the Company's control, including the outcome of future rate proceedings before the FERC or state regulatory agencies and the provisions of any final legislation or implementing regulations. The Company's future results of operations, cash flows or financial condition could be adversely affected if such costs are not recovered through regulated rates or otherwise passed on to its customers. Additionally, the Company's producer customers may also be affected by legislation or regulation, which may, directly or indirectly, adversely impact their ability and willingness to produce natural gas and accordingly affect such producers' financial health or reduce the volumes delivered to the Company and demand for its services. Climate change and GHG legislation or regulation could delay or otherwise negatively affect efforts to obtain and maintain permits and other regulatory approvals for existing and new facilities, impose additional monitoring and reporting requirements or adversely affect demand for the natural gas the Company gathers, transports and stores. The effect on the Company of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.

Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws. The Company believes that compliance with existing permits and foreseeable new permit requirements will not have a material adverse effect on its business, financial condition, results of operations, liquidity or ability to pay dividends to its shareholders.

Nationwide Permits (NWPs) are issued by the Army Corps under the Clean Water Act and the Rivers and Harbors Act of 1899 and act as a type of general permit to minimize delays and paperwork for certain activities and discharges in federal jurisdictional waters and wetlands. NWPs are typically reviewed and reissued (or modified) every five years. One such permit, NWP 12, authorizes certain “Oil or Natural Gas Pipeline Activities” and was most recently modified and reissued in January 2021. On March 28, 2022, reportedly at the request of the Biden Administration, the Army Corps initiated an early review of NWP 12 to determine whether any future actions may be appropriate to modify NWP 12 prior to its expiration in 2026. The Army Corps solicited public and stakeholder comments through public meetings held in May 2022, but has not provided any additional updates on the status of its review. To the extent future revisions to NWP 12 or litigation relating to such revisions modify its provisions with respect to oil and natural gas pipeline activities, the Company could face increased costs and delays with respect to obtaining permits for activities in jurisdictional waters, including wetlands.

Executive Order requiring a review of certain federal regulations, and in response the Council on Environmental Quality initiated a two-phase process to review NEPA regulations. Phase 1 of that process resulted in new regulations taking effect in May 2022, partially reverting NEPA regulations to rules that were in effect at the end of the Obama administration. On July 31, 2023, the Council on Environmental Quality published proposed Phase 2 revisions to NEPA regulations, including revisions to bring the regulations into compliance with changes made to NEPA by the Fiscal Responsibility Act of 2023, to increase substantive obligations placed on federal agencies in NEPA process, require consideration of climate change consequences, and require consideration of environmental justice, among other changes. The comment period for the proposed Phase 2 rules ended on September 29, 2023; a final rule is expected to follow.

On May 5, 2022, the U.S. Department of Justice (DOJ) launched a comprehensive environmental justice enforcement strategy designed to guide the DOJ’s work and ensure use of all available tools to promote environmental justice. The strategy provides a roadmap for using DOJ’s civil and criminal enforcement authorities to advance environmental justice through prioritizing enforcement of environmental and civil rights violations in overburdened communities. On the same day, DOJ also launched the Office of Environmental Justice, which has the mission of protecting overburdened and underserved communities from the harm caused by environmental crimes, pollution and climate change. The office serves as a central hub for implementing DOJ’s comprehensive environmental justice enforcement strategy and engages with all department entities to carry out this task.

Further, on September 24, 2022, the EPA launched the Office of Environmental Justice and External Civil Rights. In addition to providing resources and technical assistance on civil rights and environmental justice, the Office of Environmental Justice and External Civil Rights enforces federal civil rights laws, including Title VI of the Civil Rights Act of 1964, which prohibits discrimination by federal funding recipients.

In addition, the FERC has increased its focus on environmental justice issues in its processes and analyses. For example, in March 2023, the FERC convened the Roundtable on Environmental Justice and Equity in Infrastructure Permitting as part of its two-year Equity Action Plan to promote equity and remove barriers that underserved communities, including environmental justice communities, face in the context of the FERC’s processes and policies in five focus areas.

Equitrans Midstream is aware of these changes regarding environmental justice-related policy and enforcement and is in the process of assessing whether and how they may affect the Company. Equitrans Midstream will continue to monitor new developments and actions taken by each of these offices.

States are also in the process of reexamining environmental justice law and policy. Pennsylvania’s then governor signed Executive Order 2021-07 in October 2021. The executive order permanently created an Office of Environmental Justice within the Pennsylvania Department of Environmental Protection, formally established the existent Environmental Justice Advisory Board, and created an Environmental Justice Interagency Council. In September 2023, the Pennsylvania Department of Environmental Protection’s interim final Environmental Justice Policy became effective after an extensive public comment period. The interim final policy was subject to a public comment period that ended November 30, 2023, indicating the policy may be amended further. The prior policy had been in effect since 2004. Under the interim final policy, applications for certain Pennsylvania Department of Environmental Protection permits in environmental justice areas would be subject to specified enhanced public participation requirements, and the agency would prioritize inspections and enforcement in environmental justice areas. In Virginia, the legislature enacted the Environmental Justice Act of 2020, which requires state agencies to examine the environmental justice impacts of their actions and creates a council to recommend new environmental justice policies. In May 2023, the Virginia Department of Environmental Quality released for public comment draft guidance entitled Environmental Justice in the Permitting Process, which provides guidance to agency personnel on a permit evaluation process for permitting actions in environmental justice communities. Finalization of the guidance document remains pending. The West Virginia Department of Environmental Protection released draft Public Engagement Guidelines, which set forth guidance for agency public engagement efforts, for public comment in September 2023. The guidelines are pending finalization. Ohio appears to be monitoring developments at the EPA and other federal agencies. Many of the key issues before the states appear to be focused on enhancing public participation in permitting and other project development-related decisions. State agencies also appear to be considering new approaches to environmental justice in permitting decisions, potentially denying permits or other authorizations on environmental justice grounds. The Company will continue to monitor state legal and regulatory developments in this area and respond as appropriate.

The majority of environmental justice litigation matters appear focused on whether state or federal agencies with permitting or other decision-making responsibility have adequately considered environmental justice issues during the decision-making process. These kinds of litigation, even if unsuccessful, present risks to the underlying project’s timeline and budget. Equitrans Midstream will continue to monitor these litigation-related developments.

Equitrans Midstream takes environmental justice issues seriously and is committed to supporting the communities in which the Company operates. In July 2022, the Company published its Environmental Justice Policy that reaffirms our commitment to providing reliable energy infrastructure in a safe and responsible manner while treating all people fairly. Additionally, one of the Company’s pillars of sustainability is stakeholder engagement, including engagement with the communities where Equitrans Midstream operates. For example, Equitrans Midstream has adopted a Stakeholder Engagement and Community Investment Policy, which emphasizes early and consistent community engagement throughout project development and operation, and it specifically prioritizes environmental justice and environmental stewardship. The Company has also adopted a Human Rights Policy committing the Company to safeguarding dignity and respect for all people throughout the Company’s value chain, including through community engagement and the prevention of discrimination.

Weather affects natural gas demand for power generation and heating purposes. Peak demand for natural gas typically occurs during the winter months as a result of the heating load.

To ensure that we are well positioned to provide innovative solutions and reliable energy infrastructure services in a safe, efficient, and responsible manner and in a changing economic landscape focused on long-term, sustainable operations, the Company seeks to employ a team of highly accomplished people who are dedicated to the Company’s success and to foster an engaging workplace environment that provides for competitive pay and benefits, attractive career development opportunities, and a collaborative, respectful culture.

As of December 31, 2023, the Company had 773 employees. During 2023, the Company's overall turnover was 6% (with more than 5% being voluntary turnover) of the total employee population.

The Company also partners with several diverse organizations to broaden and extend its recruitment efforts, including HBCUConnect.com (Historically Black Colleges and Universities Connect), DiversityJobs.com, RecruitMilitary.com and GettingHired.com (representing individuals with disabilities).

The Company makes certain filings with the SEC, including its Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments and exhibits to those reports, available free of charge through its website, www.equitransmidstream.com, as soon as reasonably practicable after they are filed with or furnished to the SEC. Reports filed with, or furnished to, the SEC are also available on the SEC's website at www.sec.gov.

In addition to the other information contained in this Annual Report on Form 10-K, the following risk factors (and related summary) should be considered in evaluating our business and future prospects. The following discussion of risk factors, including the summary, contains forward-looking statements. The summary below is not exhaustive and is qualified by reference to the full set of risk factors set forth in this section.

The risk factors may be important for understanding any statement in this Annual Report on Form 10-K or elsewhere. The following information, including the full set of risk factors set forth in this section, should be read in conjunction with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and the financial statements and accompanying notes included in "Item 8. Financial Statements and Supplementary Data" in Part II of this Annual Report on Form 10-K. Note that additional risks not presently known to us or that are currently considered immaterial as of the filing of this Annual Report on Form 10-K may also have a negative impact on our business and operations. If any of the events or circumstances described below actually occurs, our business, financial condition, results of operations, liquidity or ability to pay dividends could suffer and the trading price of our common stock could decline.

Because of the following factors, as well as other variables affecting our results of operations, past performance may not be a reliable indicator of future performance, and historical trends should not be used to anticipate results or trends in future periods.

The following is a summary of the most significant risks relating to our business activities that we have identified. If any of these risks actually occur, our business could be materially adversely affected. For a more complete understanding of our material risk factors, this summary should be read in conjunction with the detailed description of our risk factors which follows this section.

Historically, we have provided EQT a substantial percentage of its natural gas gathering, transmission and water services. EQT accounted for approximately 61% of our revenues for the year ended December 31, 2023. We expect to continue to derive a substantial majority of our revenues from EQT for the foreseeable future.

Given the scope of our business relationship with EQT, any event, whether in our areas of operations or otherwise, that adversely affects EQT’s production (or the amount of its production which flows to our systems), financial condition, leverage, results of operations or cash flows may adversely affect us. Accordingly, we are subject to the business risks of EQT, including the following:

While EQT has dedicated a significant amount of its acreage to us and executed long-term contracts with substantial firm reservation and MVCs on our systems, it may determine in the future that drilling in areas outside of our current areas of operations is strategically more attractive to it, and other than the firm reservations and MVCs, it is under no contractual obligation to maintain its production dedicated to us. A substantial reduction in the capacity subscribed or volumes transported or gathered on our systems by EQT (or sustained lack of growth in respect of such volumes) could have a material adverse effect on our business, financial condition, results of operations, liquidity and our ability to pay dividends to our shareholders.

Our growth strategy includes organic optimization of our existing assets and greenfield growth projects. The development and construction by us or our joint ventures of pipeline and water infrastructure and storage facilities and the optimization of such assets involve numerous construction, business, economic, competitive, regulatory, judicial, environmental, political and legal uncertainties that are beyond our control, require the expenditure of significant amounts of capital and expose us to risks. Those risks include, but are not limited to: (i) physical construction conditions, such as topographical, or unknown or unanticipated geological, conditions and impediments; (ii) construction site access logistics; (iii) crew availability and productivity and ability to adhere to construction workforce drawdown plans; (iv) adverse weather conditions; (v) project opposition, including delays caused by landowners, advocacy groups or activists opposed to our projects and/or the natural gas industry through lawsuits or intervention in regulatory proceedings; (vi) environmental protocols and evolving regulatory or legal requirements and related impacts therefrom, including additional costs of compliance; (vii) the application of time of year or other regulatory restrictions affecting construction, (viii) failure to meet customer contractual requirements; (ix) environmental hazards; (x) vandalism; (xi) the lack of available skilled labor, equipment and materials (or escalating costs in respect thereof, including as a result of inflation); (xii) issues regarding availability of or access to connecting infrastructure; and (xiii) the inability to obtain necessary rights-of-way or approvals and permits from regulatory agencies on a timely basis or at all (and maintain such rights-of-way, approvals and permits once obtained, including by reason of judicial hostility or activism). Risks inherent in the construction of these types of projects, such as unanticipated geological conditions, challenging terrain in certain of our construction areas and severe or continuous adverse weather conditions, have adversely affected, and in the future could adversely affect, project timing, completion and cost, as well as increase the risk of loss of human life, personal injuries, significant damage to property or environmental pollution. Most notably, certain of these risks have been realized in the construction of the MVP project, including construction-related risks and adverse weather conditions, and such risks or other risks may be realized in the future which may further adversely affect the timing and/or cost of the MVP project.

Additionally, construction expenditures on projects generally occur over an extended period, yet we will not receive revenues from, or realize any material increases in cash flow as a result of, the relevant project until it is placed into service. Moreover, our cash flow from a project may be delayed or may not meet our expectations, including as a result of taxes which could potentially be calculated based on excess expenditures, inclusive of maintenance, incurred during extended court-driven construction delays. Furthermore, we may construct facilities to capture anticipated future growth in production and/or demand in a region in which such growth does not materialize or is delayed beyond our expectations. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return. Such issues in respect of the construction of midstream assets could adversely affect our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

Certain of our projects require regulatory approval from federal, state and/or local authorities prior to and/or in the course of construction, including any extensions from, expansions of or additions to our and the MVP Joint Venture’s gathering, transmission and storage systems, as applicable. The approval process for certain projects has become increasingly slower and more difficult, due in part to federal, state and local concerns related to exploration and production, transmission and gathering activities and associated environmental impacts, and the increasingly negative public perception regarding, and opposition to, the oil and gas industry, including major pipeline projects like the MVP and MVP Southgate. Further, regulatory approvals and authorizations, even when obtained, have increasingly been subject to judicial challenge by activists requesting that issued approvals and authorizations be stayed and vacated.

Accordingly, authorizations needed for our or the MVP Joint Venture’s projects, including any expansion of the MVP project and the MVP Southgate project or other extensions, may not be granted or, if granted, such authorizations may include burdensome or expensive conditions or may later be stayed or revoked or vacated, as was repeatedly the case with the construction of the MVP project, particularly in respect of litigation in the Fourth Circuit. Significant delays in the regulatory approval process for projects, as well as stays and losses of critical authorizations and permits, should they be experienced, have the potential to significantly increase costs, delay targeted in-service dates and/or affect operations for projects (among other adverse effects), as has happened with the MVP and the originally contemplated MVP Southgate projects and could occur in the future in the case of authorizations required for our or the MVP Joint Venture’s current or future projects, including in respect of developing expansions or extensions, such as expansion of the MVP project and the MVP Southgate project.

Any such adverse developments and uncertainties could adversely affect our ability, and/or, as applicable, the ability for the MVP Joint Venture and its owners, including us, to achieve expected investment returns, adversely affect our willingness or ability and/or that of our joint venture partners to continue to pursue projects, and/or cause impairments, including, as has occurred in the past, to our equity investment in the MVP Joint Venture.

"Item 1A. Risk Factors" of this Annual Report on Form 10-K. Challenges to our projects have adversely affected and could adversely affect our business (including by increasing the possibility of investor activism), financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

Prices for natural gas and NGLs, including regional basis differentials, have previously adversely affected, and may in the future adversely affect, the timing of development of additional reserves and production that is accessible by our pipeline and storage assets, which also negatively affects our water services business, and the creditworthiness of our customers. Lower natural gas prices, particularly in the Appalachian region, have in the past caused, and may in the future cause, certain producers, including certain of our customers, to determine to take actions to slow production growth and/or maintain or reduce production, which when effected by our producer customers reduces the demand for, and usage of, our services. For instance, temporary production curtailments have previously resulted in a decrease in our volumetric-based fee revenues. An extended period of low natural gas prices and/or instability in natural gas prices in future periods, especially in the Appalachian region, or other factors could cause EQT or other producers to curtail production in the future, which could have a significant negative effect on the demand for our services, our volumetric-based fee revenue, and therefore our results of operations.

Maintaining or increasing the contracted capacity or the volume of natural gas not subject to MVCs gathered, transported and stored on our systems and cash flows associated therewith is substantially dependent on our customers continually accessing additional reserves of natural gas in or accessible to our current areas of operations. For example, while EQT has dedicated production from a substantial portion of its leased properties to us, we have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our gathering and transmission systems or the rate at which production from a well naturally declines over time. EQT and other producers may not develop the acreage they have dedicated to us for a variety of reasons, including, among other things, the availability and cost of capital, corporate capital allocation policies, producers’ focus on generating free cash flow and/or de-levering, prevailing and projected energy prices, hedging strategies and environmental or other governmental regulations. Our ability to obtain non-dedicated sources of natural gas is affected by the level of successful drilling activity near our systems and our ability to compete for volumes from successful new wells, and most development areas in our areas of operation are already dedicated to us or one of our competitors.

In addition, the amount of natural gas reserves underlying wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. We do not obtain independent evaluations of natural gas reserves connected to our systems. Accordingly, we do not have independent estimates of total reserves connected to our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our systems are less than we anticipated based upon publicly available data provided by our producer customers, or the timeline for the development of reserves is longer than we anticipate, and we are unable to secure additional sources of natural gas, there could be a material adverse effect on our business, results of operations, financial condition, liquidity and ability to pay dividends to our shareholders.

GAAP requires us to test certain assets for impairment on either an annual basis or when events or circumstances occur which indicate that the carrying value of such assets might be impaired. The outcome of such testing previously has resulted in, and in the future could result in, impairments of our assets, including our property, plant, and equipment, intangible assets, goodwill and/or our equity method investment in the MVP Joint Venture. If we determine that an impairment has occurred, we would be required to take a noncash charge to earnings, which, if significant, could have a material adverse effect on our results of operations and financial position. See Note 2 to the consolidated financial statements for a discussion of impairments previously recognized.

We have become increasingly dependent upon digital technologies, including information systems, infrastructure, and cloud applications, to conduct our business, and the maintenance of our financial and other records has long been dependent upon such technologies. Our business also involves collection, uses and other processing of personally identifiable information of our employees, contractors, land agreement counterparties, and other related parties by the Company and/or our third-party business partners. We depend on both our own systems, networks, and technology as well as the systems, networks and technology of our vendors, customers and other business partners. Our increasing reliance on digital technologies puts us at greater risk for system failures, disruptions, incidents, data breaches and cyberattacks (including through third parties with which we do business), which could significantly impair our ability to conduct our business. Additionally, if our major customers or suppliers experience deliberate attacks on, or unintentional events affecting their digital technologies, it may reduce their ability to utilize our, or provide, services, which could have a material adverse impact on our operations and business. Energy industry participants, including midstream companies, have been the victims of high-profile ransomware attacks, and we expect to continue to be targeted by cyberattacks as a critical infrastructure company.

The U.S. government has continued to issue public warnings that indicate that energy assets might be specific targets of cyberattacks. The TSA has issued a series of security directives applicable to certain midstream companies, including us, requiring such companies to comply with mandatory reporting measures and undertake a number of specific cybersecurity enhancements for both IT and OT systems. In addition to the TSA security directives, there are multiple regulatory rulemaking processes, and contemplated legislation that may result in new regulations or requirements applicable to us. For additional information regarding cybersecurity matters applicable to us, including our TSA-approved CIP and laws and regulations such as the TSA security directives, see "Regulatory Environment" and "Cybersecurity" under Part I, “Item 1. Business” of this Annual Report on Form 10-K. We have been required and may further be required to expend additional resources as a result of current or new laws, regulations, directives or other requirements related to critical infrastructure cybersecurity. With the proliferation of regulations, we may become subject to overlapping or conflicting regulatory requirements. Any failure to remain in compliance with laws or regulations governing cybersecurity, including the TSA security directives, may result in penalties, fines, enforcement actions, or mandated changes in our practices, which may have a material adverse effect on our business and operations.

We rely on IT systems, some of which are managed by third parties that we do not control, that may also be, and may have been, susceptible to cyber threats and cyber-related risks described in this risk factor. While we and third parties that provide

services to us commit resources to the design, implementation and monitoring of our IT and OT systems, there is no guarantee that our or such third parties’ cybersecurity measures will provide absolute security.

Despite these measures, we may not be able to anticipate, detect or prevent all cyberattacks or incidents, particularly because the methodologies used by attackers change frequently or may not be recognized until launched, and because attackers are increasingly using tactics, techniques, and procedures designed to circumvent controls and avoid detection. Attacks may originate from outside or inside parties, hackers, criminal organizations, or other threat actors, including nation states. As artificial intelligence (“AI”) capabilities improve and gain widespread use, we may experience cyberattacks created using AI or incidents related to the use of AI, which may be difficult to detect and mitigate against.

Deliberate attacks on, or unintentional events or incidents affecting, our IT and OT systems or infrastructure or the systems or infrastructure of third parties could, depending on the extent or duration of the event, materially adversely affect us, including by leading to corruption, misappropriation or loss of our proprietary and sensitive data, delays (which could be significant) in the performance of services for our customers, difficulty in completing and settling transactions, challenges in maintaining our books and records, communication interruptions, environmental damage, regulatory scrutiny, personal injury or death, property damage and other operational disruptions, as well as damage to our reputation, financial condition and cash flows and potential legal claims and liabilities. Like other companies in the natural gas industry, we have identified and expect to continue to identify cyberattacks and incidents on our systems. Additionally, we have received notification from third party service providers of certain such matters on their systems. None of the cyberattacks and incidents we have identified, or been notified of, to the filing of this Annual Report on Form 10-K has had a material impact on our business or operations.

Further, as cyberattacks continue to evolve and increase in sophistication and volume, we have expended, and expect to continue to expend, additional resources relating to cybersecurity, including, as applicable, to continue to modify or enhance our preventive, protective, and response measures and/or to investigate and remediate potential vulnerabilities to or consequences of cyberattacks and incidents. There can be no assurance that any preventive, protective, response, or remedial measures will address or mitigate all threats that arise.

The regulatory landscape with regard to data privacy continues to rapidly develop in foreign, federal and state jurisdictions. Compliance with new laws and regulations governing data privacy, as well as any unauthorized disclosure of personal information, is becoming increasingly complex and may potentially increase our compliance costs. Any failure by us, a company that we acquire, or one of those third parties on which we rely, to comply with these laws and regulations, where applicable, could adversely affect us, including by resulting in reputational harm, penalties, regulatory investigations scrutiny, liabilities, legal claims and/or mandated changes in our business practices.

Our subsidiaries have significant amounts of debt outstanding under the Amended EQM Credit Facility, the 2021 Eureka Credit Facility (as such terms are defined in Note 9) and the senior unsecured notes issued by EQM. See Note 9 to the consolidated financial statements for a discussion of the Amended EQM Credit Facility, the 2021 Eureka Credit Facility and the senior unsecured notes issued by EQM and see Note 15 to the consolidated financial statements for a discussion of the Fifth Amendment to the Amended EQM Credit Facility. The respective debt agreements of EQM and Eureka Midstream, LLC (Eureka), a wholly owned subsidiary of Eureka Midstream, contain various covenants and restrictive provisions that limit EQM’s and Eureka’s, as applicable, ability to, among other things: incur or guarantee additional debt, make distributions on or redeem or repurchase units, incur or permit liens on assets, enter into certain types of transactions with affiliates, enter into burdensome agreements, subject to certain specified exceptions, enter into certain mergers or acquisitions; and, dispose of all or substantially all of their respective assets.

The Amended EQM Credit Facility contains certain negative covenants, that, among other things, establish for EQM a maximum Consolidated Leverage Ratio (as defined in the Amended EQM Credit Facility) that could not exceed 5.85 to 1.00 for the quarter ended December 31, 2023, 6.00 to 1.00 for the quarter ending March 31, 2024, 6.25 to 1.00 for the quarter ending June 30, 2024, 5.85 to 1.00 for the quarter ending September 30, 2024, and 5.50 to 1.00 for quarters thereafter, with the then-applicable ratio being tested as of the end of each fiscal quarter. Under the 2021 Eureka Credit Facility, Eureka is required to maintain a Consolidated Leverage Ratio (as defined in the 2021 Eureka Credit Facility) of not more than 4.75 to 1.00 (or not more than 5.25 to 1.00 for certain measurement periods following the consummation of certain acquisitions). Additionally, as of the end of any fiscal quarter, Eureka may not permit the ratio of Consolidated EBITDA (as defined in the 2021 Eureka Credit Facility) for the four fiscal quarters then ending to Consolidated Interest Charges (as defined in the 2021 Eureka Credit Facility) to be less than 2.50 to 1.00.

In addition, the Amended EQM Credit Facility and the 2021 Eureka Credit Facility each contain certain events of default, including the occurrence of a change of control (as defined in the applicable credit facility). Events beyond the control of EQM and Eureka (including changes in general economic and business conditions) and with respect to EQM, certain delays in the full in-service of the MVP project (absent mitigating actions by management), may affect the ability of EQM and Eureka to, as applicable, meet and comply with their respective financial obligations and covenants.

The provisions of the debt agreements may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of these debt agreements could result in an event of default, which could enable creditors to, subject to the terms and conditions of the applicable agreement, declare any outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of the debt is accelerated, our assets may be insufficient to repay such debt in full, and in turn our shareholders could experience a partial or total loss of their investments. The Amended EQM Credit Facility and the 2021 Eureka Credit Facility each contain a cross default provision that applies to a default related to any other indebtedness the applicable borrower may have with an aggregate principal amount in excess of $25 million as to EQM, and $10 million as to Eureka.

Our subsidiaries’ levels of debt could have important consequences to us, including that our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired, or such financing may not be available on favorable terms; our funds available for operations, future business opportunities and dividends to our shareholders may be reduced by that portion of our cash flow required to make interest payments on our or our subsidiaries’ debt; we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and our flexibility in responding to changing business and economic conditions may be limited.

Our ability to service our subsidiaries’ current, or our or our subsidiaries’ future respective debts, will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. Further, we view de-levering our business as a critical strategic objective given that leverage levels affect the manner in which we may pursue strategic and organic initiatives, our ability to respond to market and competitive pressures, and the competition for investment capital. Our ability to de-lever and the pace thereof will depend on our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors (including particularly bringing the MVP in-service), as well as the MVP Joint Venture’s ability to execute on project-level financing, some of which are beyond our control.

If our operating results are not sufficient to service our subsidiaries’ current, or our or our subsidiaries’ future indebtedness, as applicable, or our operating results affect our ability to comply with covenants in our debt agreements, we will be forced to take actions such as seeking modifications to the terms of our debt agreements (for example, the Amended EQM Credit Facility has been amended to increase the Consolidated Leverage Ratio in the past), including providing guarantees, pledging assets as collateral, reducing dividends, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity or debt capital. We may not be able to timely effect any of these actions on satisfactory terms or at all. Further, if our operating results are not sufficient to enable de-levering or affect the pace of de-levering, or if MVP project-level financing is not realized, the manner in which we may pursue strategic and organic initiatives, address market and competitive pressures, and compete for investment capital may be adversely affected, absent additional actions to de-lever, which may not be available to us on satisfactory terms or at all.

Our subsidiaries’ current substantial indebtedness and the additional debt we and/or our subsidiaries will incur in the future for, among other things, working capital, repayment of existing indebtedness, capital expenditures, capital contributions to the MVP Joint Venture, acquisitions or operating activities may adversely affect our liquidity and therefore our ability to pay dividends to our shareholders.

As of February 20, 2024, EQM’s credit ratings were Ba3 with a stable outlook, BB- with a negative outlook and BB on Rating Watch Positive from Moody’s, S&P and Fitch, respectively. EQM’s credit ratings have fluctuated (and may further fluctuate) depending on, among other things, EQM’s leverage, in-service timing and total project cost of the MVP project, and the credit profile of our customers.

EQM’s credit ratings are subject to further revision or withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating. We cannot ensure that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a credit rating agency if, in its judgment, circumstances so warrant, including in connection with the MVP project, EQM's leverage or the creditworthiness of EQM’s customers. Credit rating agencies perform an independent analysis when assigning credit ratings. This analysis includes a

number of criteria such as business composition, market and operational risks, various financial tests, ESG matters, as well as analysis of various financial metrics. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time.

If any credit rating agency further downgrades or withdraws EQM’s ratings, including for reasons relating to the MVP project (such as for delays affecting the MVP project or increases in such project’s targeted costs), EQM’s leverage or credit ratings of our customers, our subsidiaries’ respective access to the capital markets could become more challenging, borrowing costs will likely increase, our operating flexibility may be adversely affected, EQM may be required to provide additional credit assurance (the amount of which may be substantial) in support of commercial agreements such as joint venture agreements, and the potential pool of investors and funding sources may decrease.

In order to be considered investment grade, EQM must be rated Baa3 or higher by Moody’s, BBB- or higher by S&P and BBB- or higher by Fitch. EQM’s non-investment grade credit ratings have resulted in greater borrowing costs, including under the Amended EQM Credit Facility, and increased collateral requirements, including under the MVP Joint Venture’s limited liability company agreement, than if EQM’s credit ratings were investment grade.

In addition to causing, among other impacts, higher borrowing costs and/or more restrictive terms associated with modifications to existing debt instruments, any further downgrade could also require additional or more restrictive covenants on future indebtedness that impose operating and financial restrictions on us or our subsidiaries, certain of our subsidiaries to guarantee such debt and certain other debt, and certain of our subsidiaries to provide collateral to secure such debt.

Any increase in our financing costs resulting from a credit rating downgrade, and/or more restrictive covenants or the pledging of security, could adversely affect our ability to finance future operations and limit our operating flexibility. If a credit rating downgrade and/or a resultant collateral requirement were to occur at a time when we are experiencing significant working capital requirements or otherwise lack liquidity, our business, results of operations, liquidity and ability to pay dividends to our shareholders could be adversely affected.

Companies across all industries are facing increasing scrutiny from stakeholders related to their ESG and sustainability practices. Investor advocacy groups, proxy advisory firms, certain institutional investors and lenders, investment funds and other influential investors and rating agencies are also increasingly focused on ESG and sustainability practices and matters and on the implications and social cost of their investments and loans. Increased focus related to ESG and sustainability matters may adversely affect our business, financial condition, results of operations, and liquidity, as well as our stock price, and expose us to new or additional risks, including as described below.

We recognize that our shareholders, employees, customers, regulators, and other stakeholders expect us to continue to focus and report on long-term sustainable performance, including by addressing significant, relevant ESG factors, further working to prioritize sustainable energy practices, reducing our carbon footprint and promoting sustainability. We have incurred and expect to continue to incur costs and capital expenditures in doing so, and certain of such future costs and capital expenditures could be material, including because of increasing regulatory demands, which may not be consistent in their requirements. For example, California enacted two climate related disclosure laws called the Climate Corporate Data Accountability Act (“CCDAA”) and the Climate-Related Financial Risk Act (“CRFRA”) on October 7, 2023. Further, on March 21, 2022, the SEC released proposed rule changes that would require new climate-related disclosure in SEC filings. For additional information regarding the SEC’s climate related disclosures rule, the CCDAA and the CRFRA, please see “Regulatory Environment — Climate Change” under Part I, "Item 1. Business" of this Annual Report on Form 10-K. The CCDAA and the CRFRA would, and the SEC’s climate related disclosures rule if adopted as proposed would, cause us to incur additional (and potentially accelerate) compliance and reporting costs, certain of which could be material, including related to monitoring, collecting, analyzing and

reporting new metrics and implementing systems and procuring necessary attestations, as applicable. Such costs, or costs or impacts associated with any failures to comply with such or any similar laws, may adversely affect our future business, financial condition, results of operations, and liquidity.

Further, if we do not adapt to or comply with investor or other stakeholder expectations and standards, which are evolving, or if we are perceived not to have responded appropriately or quickly enough to growing concern for ESG and sustainability issues, our business could suffer, including from reputational damage (and negative public perception regarding us or our industry may lead to additional regulatory scrutiny or other adverse developments). We have disclosed aspirational goals, targets, potential financial impacts and other expectations and assumptions related to reducing our carbon footprint and promoting sustainability that are necessarily uncertain due to, among other things, long implementation timelines, and thus may not be realized. Failure to realize (or timely achieve progress on) such aspirational goals, targets, cost estimates, and other expectations or assumptions may adversely impact us. Our disclosures regarding aspirational goals, targets, cost estimates, and other expectations or assumptions, as applicable, could receive increased scrutiny by shareholders or regulators which may adversely impact us, including as a result of unforeseen events which may affect us.

Additionally, activist shareholders may submit proposals to promote or oppose an ESG-related position. Responding to such proposals, proxy contests and other actions by activist shareholders can be costly and time-consuming, disrupting our operations, causing reputational harm, and diverting the attention of our Board and senior management from the pursuit of business strategies. Further, a multitude of organizations that provide information to investors have developed ratings processes for evaluating companies on their approach to ESG and sustainability matters. Such ratings and reports are used by some investors to inform their investment and voting decisions. Favorable or unfavorable ESG ratings, or perceptions of us or our industry as a result of such ratings or our ESG and sustainability practices, may lead to increased negative investor and other stakeholder sentiment toward us or our customers, and to the allocation of investment capital to other industries and companies, which could negatively affect our stock price and access to and costs of capital.

The occurrence of any of the foregoing may adversely affect our business, financial condition, results of operations, liquidity and/or our stock price.

Combating the effects of climate change continues to attract considerable attention in the United States and internationally, including from regulators, legislators, companies in a variety of industries, financial market participants, and other stakeholders. Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing risks and governmental actions that could have an adverse impact on our operations in the United States. Numerous proposals and regulations have been made and will continue to be made to monitor and limit existing GHG emissions, as well as to restrict or eliminate future emissions. Accordingly, our business and operations, and those in our value chain, including our producer customers, are subject to executive, regulatory, political, litigation, and financial risks associated with natural gas and the emission of GHGs.

At the federal level, the United States has taken steps to address climate change through legislative action, executive actions, and regulatory initiatives pursuant to existing statutes, such as the Clean Air Act. The EPA released in December 2023 its final rule, which has not yet been published in the Federal Register as of the filing of this Annual Report on Form 10-K, regulating methane emissions from the oil and gas sector under the Clean Air Act. The Inflation Reduction Act of 2022 amended the Clean Air Act to require a “methane fee” for specific facilities that exceed GHG emission and/or methane intensity thresholds beginning in 2024. These new Clean Air Act regulations, as well as any other future laws or regulations that legislators or federal agencies may adopt, could have an adverse impact on our operations and results thereof. State and regional efforts could establish requirements in states in which our assets, employees or customers are located regardless of federal action.

States where our, the MVP Joint Venture’s or our customers’ assets are located have entered or sought to enter into the Regional Greenhouse Gas Initiative (RGGI), which is a consortium of certain Northeastern and Mid-Atlantic states that set declining limits on CO2 emissions from fossil fuel fired power plants. Initiatives such as RGGI, if enforceable in our areas of operation, may result in increased uncertainty regarding demand for natural gas used in the generation of electricity, including in our operating markets. Beyond regional and state efforts, nationally, demand for natural gas used in the generation of electricity could also be affected by federal action, such as the EPA’s proposed rulemaking to regulate GHG emissions from new and existing fossil fuel fired power plants.

There remains considerable uncertainty surrounding the timing, scope and potential impact of future state, national and international action with respect to GHG emissions, including methane in particular. Although we continue to monitor legislative, regulatory, and judicial developments in this area to assess potential impacts on our operations and otherwise take efforts and invest funds proactively to limit and reduce GHG emissions from our facilities, we cannot predict what form future laws, regulations, and legal requirements relating to climate change might take. Nor can we predict the stringency of any such requirements, when they might become effective, or their exact effect on us. Further, laws, regulations, and other legal requirements relating to climate change are constantly changing or being interpreted or reinterpreted, and this may occur during the permitting and construction phases of our projects, and may result in increased costs and delays. Generally, development and implementation of processes to comply with changing legal requirements are likely to be costly and time consuming. Laws, regulations and legal requirements designed to reduce GHG emissions also may: (i) make some of our activities, or those of our customers, uneconomic or less economically advantageous to maintain or operate, which may affect the estimated fair values of underlying assets and results of operations; (ii) reduce the number of attractive business opportunities available to us and discourage investments in our securities; (iii) impose additional and costly compliance obligations such as new emission control requirements, taxes, fees or other costs on the release of GHGs, cause longer permitting timelines, require that we purchase allowances for emissions, expose us to regulatory penalties or affect our reputation; and (iv) adversely affect production of or demand for natural gas (such as by increasing the cost of producing natural gas, increasing the cost of producing electricity with natural gas, or prompting consumers to use renewable fuels).

If any of the foregoing events were to occur, it may have an adverse effect on our business, financial condition, results of operations, liquidity or ability to pay dividends to our shareholders. Although future laws, regulations, and legal requirements relating to climate change could have a material impact on our industry and us, attempts at quantification are based on speculation of what may occur in the future which is inherently uncertain.

Litigation risks relating to climate change continue to increase. Parties have brought suit against certain large oil and natural gas exploration and production companies, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to climate change effects, such as rising sea levels, and therefore are responsible for resultant damages. Parties have also alleged that these companies have been aware of the adverse effects of climate change for some time but misled their investors and consumers by failing to adequately disclose those impacts. While we are not currently party to any such litigation as of the filing of this Annual Report on Form 10-K, we, joint ventures in which we participate, or third parties with which we do business could be named in future actions given that our or their business involves natural gas. Further, climate change-related factors may prompt governmental investigations or adversely affect the regulatory approval process for the construction and operation of midstream assets, as, for example, opposition parties have cited, and are likely to cite in the future, our and/or the MVP Joint Venture's direct and/or indirect GHG emissions as a specific concern during comment periods for regulatory permit reviews.

Market forces driven by concern for climate change are also affecting (and are expected to continue to affect) the availability and cost of capital to companies in the fossil fuel sector. For example, climate change activists continue to direct their attention towards, among other things, sources of funding for fossil fuel energy companies, which has resulted in certain financial institutions, funds, and other sources of capital restricting or adding more burdensome terms to or altogether eliminating their investments in, or lending with respect to, fossil fuel energy-related activities and companies (as we have experienced with respect to the Amended EQM Credit Facility (as defined in Note 9), and in the future could experience). Further, such institutions are increasingly allocating funds to those industries and companies perceived as having better growth opportunities and/or stronger ESG metrics and practices. These market forces may adversely affect our ability to obtain financing in the future (and thus our pursuit of initiatives, such as growth projects) or achieve increases in our stock price, and these forces may also adversely affect our customers, which could result in, among other things, increased counterparty risk and/or decreased demand for our services. Further, the concern surrounding climate change is increasing demand for lower-carbon technologies and alternate forms of energy in the marketplace, which is driving innovation and investment in products that compete with natural gas. Continued momentum to develop and drive down the cost of competitive energy alternatives may adversely affect demand for natural gas and accordingly our producer customers.

In addition to such transitional risks, climate change also may create physical risks to our business. Climate impacts, such as increasing temperatures, changing weather patterns, and more frequent or intense floods and storms, can pose serious challenges for our facilities, supply chains, employees, contractors, current and potential customers, and the communities in which we operate. In particular, our operations are primarily located in the Appalachian Basin, which is a rain-susceptible region and given its geography there is inherent risk associated with landslides which could increase with climate change. Further, climate-induced rainfall events and severe storms above and beyond historical estimates, magnitudes, and frequency could exceed the pre-designed environmental controls in place on our construction projects, and/or cause pipeline slips or other damage to our physical assets, especially facilities located in low-lying areas near streams and riverbanks and pipelines situated in landslide-prone and rain-susceptible regions, which may adversely affect or temporarily interrupt our operations. We may not be able to pass on resultant financial impacts to our customers or recover all costs related to mitigating these physical risks or

repairing damage due to such events. Further, our ability to mitigate the adverse impacts of these events depends in part on the resilience of our environmental controls, facilities and the effectiveness of planning for disaster preparedness and response and business continuity, which plans may not fully encompass every potential climate-driven eventuality. Additionally, changing climate patterns could impact the demand for energy in the regions we currently and plan to serve. For example, extreme warm weather in the winter months may lead to decreased natural gas usage, which may affect our results of operations and financial condition.

One or more of any such developments could have an adverse effect on our business, financial condition, results of operations, liquidity or ability to pay dividends to our shareholders.

For additional information on GHG laws, regulations and other legal requirements applicable to us, see “Regulatory Environment — Environmental Matters” under “Item 1. Business” in Part I of this Annual Report on Form 10-K.

Negative public perception regarding us, the MVP, MVP Southgate, other of our or the MVP Joint Venture’s extension or expansion projects and/or our industry, resulting from, among other things, concerns raised by advocacy groups regarding climate change; oil or produced water spills; gas and other hydrocarbon leaks; the explosion or location of natural gas transmission and gathering lines and other facilities; erosion and sedimentation issues; hydraulic fracturing, environmental justice concerns; as well as general and specific concerns relating to our operations or pipeline and expansion projects, has led to, and may in the future lead to, increased regulatory scrutiny, and/or new local, state, and federal safety and environmental laws, regulations, guidelines, enforcement interpretations and/or adverse judicial rulings or regulatory actions.

These actions have caused, and may continue to cause, operational delays or restrictions, increased construction and operating costs, penalties under construction contracts, additional regulatory burdens, and increased litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance, and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could further cause the permits we and the MVP Joint Venture need to complete extension or expansion projects, including the MVP Southgate project and any expansion of the MVP, and to conduct our and its respective operations to be denied, removed, withheld, delayed, stayed or burdened by requirements that restrict our and its respective abilities to profitably conduct business or make it more difficult to obtain the real property interests needed to operate relevant assets or complete planned growth projects, which could, among other adverse effects, affect project completion or subsequent operation, result in revenue loss or a reduction in our and the MVP Joint Venture’s customer bases.

We rely exclusively on revenues generated from our gathering, transmission and storage and water systems, substantially all of which are located in the Appalachian Basin in Pennsylvania, West Virginia and Ohio, and as of December 31, 2023 dry natural gas comprised approximately 86% of our product portfolio. Due to our lack of diversification in assets, products and geographic location and the challenging environment for completing transmission projects such as the MVP and MVP Southgate, an adverse development in these businesses or our areas of operations, including adverse developments due to catastrophic events, pandemics, epidemics, weather, regulatory action, local prices, producer liquidity or production determinations, decreases in

demand for natural gas from the Appalachian Basin, takeaway capacity constraints from the Appalachian Basin (including as may remain long term notwithstanding any completion of MVP and limit our producer customers’ future ability to grow production volumes to then-existing pipeline capacity and consequently affect natural gas prices adversely within the Appalachian Basin) or increases in supply of natural gas from other natural gas or oil producing basins (such as associated gas production from the Permian Basin) could have a more significant impact on our business, financial condition, results of operations, liquidity and our ability to pay dividends than if we maintained more diverse assets, products and locations.

We are exposed to the risk of loss resulting from the nonpayment and/or nonperformance of our customers, suppliers, joint venture partners and other counterparties as further described in “Credit Risk” under Part II, “Item 7A. Quantitative and Qualitative Disclosure About Market Risk” of this Annual Report on Form 10-K. We extend credit to our customers as a normal part of our business. While we have established credit policies, including assessing the creditworthiness of our customers as permitted by our FERC-approved natural gas tariffs, and may require appropriate terms or credit support from them based on the results of such assessments, including in the form of prepayments, letters of credit, or guaranties, we may not adequately assess the creditworthiness of our existing or future customers or any other party and our credit policies cannot completely eliminate credit risk. Pursuant to certain agreements with EQT, amongst other things, (a) we agreed to relieve certain credit posting requirements for EQT, in an amount up to approximately $250 million under its commercial agreements with us, subject to EQT maintaining a minimum credit rating from two of three rating agencies of (i) Ba3 with Moody’s, (ii) BB- with S&P and (iii) BB- with Fitch, however, there can be no assurance that EQT will maintain sufficient credit ratings or such rating thresholds are protective against all credit risk in the case of EQT.

Periods of natural gas price declines and sustained periods of low natural gas and NGL prices, previously have had, and could in the future have, an adverse effect on the creditworthiness of our customers, including their ability to pay firm reservation fees under long-term contracts. Periods of low commodity prices have previously negatively impacted natural gas producers causing some producers significant economic stress including, in certain cases, to file for bankruptcy protection or to seek renegotiated contracts. We cannot predict the extent to which the businesses of our counterparties would be impacted if commodity prices decline, commodity prices are depressed for a sustained period of time, or other conditions in the energy industry were to deteriorate, nor can we estimate the impact such conditions would have on the abilities of our customers to perform under their gathering, transmission and storage and water services agreements with us. To the extent one or more of our counterparties is in financial distress or commences bankruptcy proceedings, contracts with these counterparties may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code (Bankruptcy Code). Nonpayment and/or nonperformance by our counterparties and/or any unfavorable renegotiation or rejection of contracts under the Bankruptcy Code could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

Additionally, we face and expect to continue to face staunch and protracted opposition to the development of expansion and extension projects (such as has been case with the MVP and MVP Southgate projects) and operation of our pipelines and facilities from environmental groups, certain landowners, local, regional and national groups opposed to the natural gas industry and/or fossil fuels generally, activists and other advocates. Such opposition has taken and will likely continue to take many forms, including organized protests, attempts to block, vandalize or sabotage our development or operations, intervention in regulatory or administrative proceedings involving our assets directly or indirectly, lawsuits or other actions designed to prevent, disrupt or delay the development or operation of our assets and business.

Any event that delays or interrupts (or continues to delay or interrupt) the completion of expansion or extension projects, and/or revenues generated, or expected to be generated, by our operations or that causes us to make significant expenditures associated with delayed construction completion or not covered by insurance, could adversely affect our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

Failure to achieve growth could adversely affect our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

On November 6, 2022, we became aware of natural gas venting from a storage well (well 2244) at Equitrans, L.P.’s Rager Mountain natural gas storage facility, located in Cambria County, Pennsylvania, which venting was halted on November 19, 2022 (the Rager Mountain natural gas storage field incident). During and continuing since the occurrence of the incident, we have incurred costs and expenses relating to or arising out of the incident, including in connection with a root cause analysis of the incident, which was conducted by an independent, third-party company with expertise in reservoir management and well and corrosion engineering and which was submitted to the PHMSA in August 2023.

Although in October 2023, following authorization from the PHMSA of our injection plan for the Rager Mountain facility, we returned the Rager Mountain facility, other than well 2244 and two additional wells, to injection operations, as discussed in Part I, “Item 3. Legal Proceedings” of this Annual Report on Form 10-K, the PADEP, the PHMSA and other investigators are continuing to conduct civil and criminal investigations of the incident and we and our subsidiary Equitrans L.P., as applicable, are cooperating in such investigations. There can be no assurance as of the filing of this Annual Report on Form 10-K as to the outcome of any investigation or pending or future proceeding with respect to the Rager Mountain natural gas storage field incident, nor can there be any assurance regarding the scope of potential (or ultimately actual) financial or other impacts or sanctions to the Company as a result of such incident. Certain of the statutory provisions cited by the PADEP in certain notices of violation relating to the incident provide for a maximum penalty of up to $25,000 per day of violation, and if penalties are pursued and ultimately imposed related to the Rager Mountain natural gas storage field incident, the penalties are expected to result in monetary sanctions in excess of $300,000.

Financial Condition and Results of Operations” of this Annual Report on Form 10-K for further information regarding the Rager Mountain natural gas storage field incident.

Our business operations are subject to the inherent hazards and risks normally incidental to the gathering, transmission and storage of natural gas and performance of water services. These operating risks, some of which we have experienced and/or could experience in the future, include but are not limited to:

Our ability to renew or replace existing contracts or add new contracts at rates sufficient to maintain or grow current revenues and cash flows could be adversely affected by the activities of our competitors. Our systems compete primarily with other interstate and intrastate pipelines and storage facilities in the gathering, transmission and storage of natural gas. Some of our competitors have greater financial resources and may be better positioned to compete, including if the midstream industry moves towards greater consolidation; further, some of such competitors may now, or in the future, have access to greater supplies of natural gas or water than we do. Some of these competitors may expand or construct gathering systems, transmission and storage systems and water systems that would create additional competition for the services we provide to our customers. In addition, certain of our customers, including EQT, have developed or acquired their own gathering and water infrastructure, and may acquire or develop gathering, transmission or storage and/or water infrastructure in the future, which could have a negative impact on the demand for our services depending on the location of such systems relative to our assets and our producer customers’ drilling plans, commodity prices, existing contracts and other factors.

The policies of the FERC promoting competition in natural gas markets continue to have the effect of increasing the natural gas transmission and storage options for our customer base. As a result, we have experienced, and in the future could experience, “turnback” of firm capacity as existing agreements expire. If we are unable to remarket this capacity or can remarket it only at substantially discounted rates compared to previous contracts, we may have to bear the costs associated with the turned back capacity. Increased competition could reduce the volumes of natural gas transported or stored on our systems or, in cases where we do not have long-term firm contracts, could force us to lower our transmission or storage rates. Increased competition could also adversely affect demand for our water services.

Further, natural gas as a fuel competes with other forms of energy available to end-users, including coal, liquid fuels and, increasingly, renewable and alternative energy. Demand for and development of renewable and alternative energy is increasing as a result of concern regarding climate change. Further, the availability of renewable and alternative energy is growing, and it continues to become more cost competitive with fossil fuels, including natural gas. Continued increases, whether driven by legislation, regulation or consumer preferences, in the availability and demand for renewable and alternative energy at the expense of natural gas (or increases in the demand for other sources of energy relative to natural gas based on price and other factors) could adversely affect our producer customers and lead to a reduction in demand for our natural gas gathering, transmission and storage, and water services.

In addition, competition, including from renewable and alternative energy, could intensify the negative impact of factors that decrease demand for natural gas in the markets served by our systems, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas.

All of these competitive pressures could make it more difficult for us to retain our existing customers and/or attract new customers and/or additional volumes from existing customers as we seek to maintain and expand our business, which could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

One of our exposures to market risk occurs at the time our existing contracts expire and are subject to renegotiation and renewal. As these contracts expire, we may have to negotiate extensions or renewals with existing customers or enter into new contracts with existing customers or other customers. We may be unable to do so on favorable commercial terms, if at all. Further, we also may be unable to maintain the economic structure of a particular contract with an existing customer or the overall mix of our contract portfolio. The extension or renewal of existing contracts and entry into new contracts depends on a number of factors beyond our control, including, but not limited to: (i) the level of existing and new competition to provide services to our markets; (ii) macroeconomic factors affecting natural gas economics for our current and potential customers; (iii) the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets; (iv) the extent to which the customers in our markets are willing to contract on a long-term basis or require capacity on our systems; (v) customers’ existing and future downstream commitments; and (vi) the effects of federal, state or local regulations on the contracting practices of our customers and us. For more information related to contracting practices applicable to certain of our services, see “Regulatory Environment — FERC Regulation” under Part I, “Item 1. Business” of this Annual Report on Form 10-K. Additionally, disagreements may arise with contractual counterparties on the interpretation of contractual provisions, as had been the case with EQT with the Hammerhead gathering contract, including during the negotiation, for example, of contract amendments required to be entered into upon the occurrence of specified events.

Any failure to extend or replace a significant portion of our existing contracts or to extend or replace our significant contracts, or extending or replacing contracts at unfavorable or lower rates or with lower or no associated firm reservation fee revenues, or other disadvantageous terms relative to the prior contract structure, or disagreements or disputes on the interpretation of existing or future contractual terms, could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

Our ability to increase our customer-subscribed capacity and throughput and resulting revenue is subject to numerous factors beyond our control, including competition from producers’ existing contractual obligations to competitors, the location of our assets relative to those of competitors for existing or potential producer customers (or such producer customers’ own midstream assets), takeaway capacity constraints out of the Appalachian Basin, commodity prices, producers’ optionality in utilizing our (relative to third-party) systems to fill downstream commitments, and the extent to which we have available capacity when and where shippers require it. To the extent that we lack available capacity on our systems for volumes, or we cannot economically increase capacity, we may not be able to compete effectively with third-party systems for additional natural gas production in our areas of operation and capacity constraints, as well as commodity prices, may, as has occurred in the past, adversely affect the degree to which natural gas production occurs in the Appalachian Basin, and relatedly the degree to which our systems are utilized.

Our efforts to attract new customers or larger commitments from existing customers may be adversely affected by our desire to provide services pursuant to long-term firm contracts and contracts with MVCs. Our potential customers may prefer to obtain services under other forms of contractual arrangements which could require volumetric exposure or potentially direct commodity exposure, and we may not be willing to agree to such other forms of contractual arrangements.

We depend on third-party pipelines and other facilities that provide receipt and delivery options to and from our transmission and storage system. For example, our and the MVP Joint Venture’s (once MVP is placed in-service) transmission, and our storage, system interconnects, as applicable, with the following third-party interstate pipelines: Transcontinental Gas Pipe Line Company, LLC (Transco), East Tennessee Natural Gas, Texas Eastern, Eastern Gas Transmission, Columbia Gas Transmission, Tennessee Gas Pipeline Company, Rockies Express Pipeline LLC, National Fuel Gas Supply Corporation and ET Rover Pipeline, LLC, as well as multiple distribution companies. Similarly, our gathering systems have multiple delivery interconnects to multiple interstate pipelines. In the event that our or the MVP Joint Venture's access to such systems is impaired (or any third party refuses to accept our or any of the MVP Joint Venture's deliveries), our or the MVP Joint Venture's operations could be adversely affected, resulting in adverse economic impact to us or the MVP Joint Venture. We have been affected by certain such circumstances in the past, which for example has reduced revenues from our gathering activities.

Because we do not own these third-party pipelines or facilities, their continuing operation and access requirements are not within our control. If these or any other pipeline connections or facilities were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity or any other reason, our (or, with MVP in-service, the MVP Joint Venture’s) ability to operate efficiently and ship natural gas to end markets could be restricted, as has occurred in the past. Any temporary or permanent interruption at any key pipeline interconnect or facility could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

It is possible that costs to perform services under “negotiated rate” contracts could exceed the negotiated rates we have agreed to with our customers. If this occurs, it could decrease the cash flow realized by our systems and, therefore, could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders. Under FERC policy, a regulated service provider and a customer may mutually agree to a “negotiated rate,” and that contract must be filed with and accepted by the FERC. As of December 31, 2023, approximately 97% of the contracted firm transmission capacity on our system was subscribed under such “negotiated rate’’ contracts. Unless the parties to these “negotiated rate” contracts agree otherwise, the contracts generally may not be adjusted to account for increased costs that could

be caused by inflation, GHG emission cost (such as carbon taxes, fees, or assessments) or other factors relating to the specific facilities being used to perform the services.

We have entered into joint ventures to construct the MVP and MVP Southgate projects and a joint venture relating to Eureka Midstream, and may in the future enter into additional joint venture arrangements with third parties, including in respect of any expansion of the MVP. Joint venture arrangements may restrict our operational and corporate flexibility. Joint venture arrangements and dynamics can also divert management and operating resources in a manner that is disproportionate to our ownership percentage in such ventures. Because we do not control all of the decisions of our joint ventures or joint venture partners, it may be difficult or impossible for us to cause these joint ventures or partners to take actions that we believe would be in our or the joint venture’s best interests. Moreover, joint venture arrangements involve various risks and uncertainties, such as committing that we fund operating and/or capital expenditures, the timing and amount of which we may not control, and our joint venture partners may not act in a manner that we believe would be in our or the joint venture’s best interests, may elect not to support further pursuit of projects, and/or may not satisfy their financial obligations to the joint venture. The loss of joint venture partner support in further pursuing or funding a project may, and would in the case of the MVP project, significantly adversely affect the ability to complete the project. In addition, the MVP Joint Venture, Eureka Midstream and any joint ventures we may enter into in the future are subject to many of the same risks to which we are subject.

We have, and may in the future, engage in acquisitions, dispositions, and other strategic transactions. These transactions involve risks that have impacted and may in the future impact our ability to realize a benefit from the transaction, including, among other potential risks (and as applicable): (i) an inability to obtain necessary regulatory and third-party approvals; (ii) the timing of and conditions imposed upon us by regulators in connection with such approvals; (iii) failure to realize assumptions about volumes, revenues, capital expenditures and costs, including synergies and potential growth; (iv) an inability to secure or maintain adequate customer commitments to use the acquired systems or facilities; (v) an inability to successfully integrate the assets or businesses we acquire; (vi) we could be required to contribute additional capital to support acquired businesses or assets, and we may assume liabilities that were not disclosed to us, for which we are not indemnified or insured or for which our indemnity or insurance is inadequate; (vii) the diversion of management’s and employees’ attention from other business concerns in a manner that is disproportionate to the relative size and impact of, or ownership percentage in, such acquired assets or entities; and (viii) unforeseen difficulties operating a larger organization or in new geographic areas, with new joint venture partners or new business lines.

If risks such as the above are realized, or if a strategic transaction fails to be accretive over the long term to our cash generated from operations on a per share basis, it could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

We are not fully insured against all risks inherent in our business, including certain environmental accidents that might occur as well as many cyber events. We do not maintain insurance in the type to cover all possible risks of loss, including “wild well” coverage or certain damage caused by cyberattacks. In addition, we do not maintain business interruption insurance of the types and in amounts necessary to cover all possible risks of loss, like project delays caused by pandemics, cyberattacks, certain environmental incidents, governmental action or inaction. The occurrence of any risks not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

In addition to requiring in many instances that we are named as additional insureds on policies maintained by vendors such as construction contractors, as of the filing of this Annual Report on Form 10-K we maintain excess liability insurance that covers our and our affiliates’ legal and contractual liabilities arising out of bodily injury, personal injury or property damage, including resulting loss of use, to third parties. This excess liability insurance includes coverage for sudden and accidental pollution liability but excludes: release of pollutants subsequent to their disposal; release of substances arising from the combustion of fuels that result in acidic deposition; and testing, monitoring, clean-up, containment, treatment or removal of pollutants from property owned, occupied by, rented to, used by or in the care, custody or control of us and our affiliates. We also maintain

coverage for us and our affiliates for physical damage to assets and resulting business interruption, including, in limited circumstances, certain damage caused by cyberattacks.

Most of our insurance is subject to deductibles or self-insured retentions. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations, business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders. We may not be able to maintain or obtain insurance of the types and in the amounts we desire at reasonable rates, and we have elected and may elect in the future to self-insure a portion of our asset portfolio. The insurance coverage we have obtained or may obtain may contain large deductibles or fail to cover certain hazards or cover all potential losses. In addition, for pre-Distribution losses, we share insurance coverage with EQT, and we will remain responsible for payment of any deductible or self-insured amounts under those insurance policies. To the extent we experience a pre-Distribution loss that would be covered under EQT’s insurance policies, our ability to collect under those policies may be reduced to the extent EQT erodes the limits under those policies.

Furthermore, any insurance company that provides coverage to us may experience negative developments that could impair its ability to pay any of our claims. As a result, we could be exposed to greater losses than anticipated and may have to obtain replacement insurance, if available, at a greater cost.

Our operations are dependent upon key management, technical and professional personnel, and one or more of these individuals could leave our employment or become unavailable due to, among other things, pandemics or epidemics, natural disaster, war, act of terrorism, sustained illness or injury. The unexpected loss of the services and skills of one or more of these individuals could have a detrimental effect on us. In addition, the success of our operations depends, in part, on our ability to identify, attract, develop and retain experienced personnel. There continues to be increased competition for experienced technical and other professionals, which could increase the costs associated with identifying, attracting and retaining such personnel. Additionally, a lack of employee engagement could lead to increased employee burnout, loss of productivity, increased propensity for errors, increased employee turnover, increased absenteeism, increased safety incidents and decreased customer satisfaction, which may in turn negatively impact our results of operations and financial condition. If we cannot identify, attract, develop, retain and engage key management, technical and professional personnel, along with other qualified employees, to support the various functions of our business, our ability to compete could be harmed.

For the years ended December 31, 2023, 2022 and 2021, approximately 70%, 71% and 64%, respectively, of our operating revenues were generated from firm reservation fee revenues. Consequently, cash flows generated from such revenues generally had limited exposure to commodity price risks. However, cash flows that are not derived from firm reservation fees, such as those derived from our volumetric-based services, do create a level of exposure to commodity price risk in that producer customers may adjust their plans as a result of changes in the commodity price environment. Although our goal is to continue to seek to contractually minimize our exposure to commodity price risk in the future by executing long-term firm reservation fee, MVC and ARC contracts with new or existing customers, our efforts to obtain such contractual terms may not be successful. In addition, we may acquire or develop additional midstream assets in the future that do not provide services primarily based on capacity reservation charges, MVCs, ARCs or other fixed fee arrangements and therefore may have a greater exposure to fluctuations in customer volume variability driven by commodity price risk. Our existing and future exposure, primarily through volumetric-based services, to the volatility of natural gas prices, including regional basis differentials with regard to natural gas prices, and any significant increase to such exposure could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

Additionally, the EQT Global GGA provides for potential cash bonus payments payable by EQT to us during the period beginning on the first day of the calendar quarter in which the MVP full in-service date occurs through the calendar quarter ending December 31, 2024 (the Henry Hub cash bonus payment provision). The fair value of the derivative asset attributable to the Henry Hub cash bonus payment provision is largely determined by estimates of the NYMEX Henry Hub natural gas forward price curve and probability-weighted assumptions regarding MVP full in-service timing, and payments are conditioned upon the quarterly average of certain Henry Hub natural gas prices exceeding certain price thresholds. The NYMEX Henry Hub future price of natural gas is a widely used benchmark for the price of natural gas in the United States. Based on the Henry Hub natural gas forward strip prices as of February 16, 2024 and the terms of the Henry Hub cash bonus payment provision, any adverse change in assumptions regarding the MVP project may further decrease the estimated fair value of the derivative asset attributable to the Henry Hub cash bonus payment provision, and such adverse change or simply commodity prices on their own could ultimately result in further decreases to such estimated fair value, including to zero. Such changes in estimated fair value, if any, would be recognized in other income (expense), net, on our statements of consolidated comprehensive income. Depending on the future NYMEX Henry Hub prices, payments under the Henry Hub cash bonus payment provision may not be triggered even if MVP were to be placed in-service (and, even if prices are sufficient to meet necessary thresholds, payments will not be triggered if the MVP is not placed in-service in or before the quarter ending December 31, 2024), which could have an adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

We do not own all of the land on which our pipelines, storage systems and facilities have been constructed, and we have been, and in the future could be, subject to more onerous terms, and/or increased costs or delays, in attempting (or by virtue of the need to attempt) to acquire or to maintain use rights to land. See “Item 2. Properties” in Part I of this Annual Report on Form 10-K for additional information. Although many of these rights are perpetual in nature, we occasionally obtain the rights to construct and operate our pipelines and other facilities on land owned by third parties and governmental agencies for a specific period of time or in a manner in which certain facts could give rise to the presumption of the abandonment of the pipeline or other facilities. As has been the case in the past, if we were to be unsuccessful in negotiating or renegotiating rights-of-way or easements, we might have to institute condemnation proceedings on our FERC-regulated assets, the potential for which may have a negative effect on the timing and/or terms of FERC action on a project’s certification application and/or the timing of any authorized activities, or relocate our facilities for non-regulated assets. The FERC has announced a policy that would presumptively stay the effectiveness of certain future construction certificates, which may limit when we are able to exercise condemnation authority. It is possible that the U.S. Congress may amend Section 7 of the NGA to codify the FERC's presumptive stay or otherwise limit, modify, or remove the ability to utilize condemnation. It is also possible that a court may limit, modify or remove an operator’s ability to utilize condemnation under Section 7 of the NGA. A loss of rights-of-way, lease or easements or a relocation of our non-regulated assets could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders. Additionally, even when we own an interest in the land on which our pipelines, storage systems and facilities have been constructed, agreements with correlative rights owners have caused us to, and in the future may require that we, relocate pipelines and facilities or shut in storage systems and facilities to facilitate the development of the correlative rights owners’ estate, or pay the correlative rights owners the lost value of their estate if they are not willing to accommodate development.

Our and the MVP Joint Venture’s interstate natural gas transmission and storage operations, as applicable, are regulated by the FERC under the NGA and the NGPA and the regulations, rules and policies promulgated under those and other statutes. Our and the MVP Joint Venture’s FERC-regulated operations are pursuant to tariffs approved by the FERC that establish rates (other than market-based rate authority), cost recovery mechanisms and terms and conditions of service to our customers. The FERC’s authority extends to a variety of matters relevant to our operations. For additional information, see “Regulatory Environment — FERC Regulation” under “Item 1. Business” in Part I of this Annual Report on Form 10-K.

Pursuant to the NGA, existing interstate transmission and storage rates, terms and conditions of service, and contracts may be challenged by complaint and are subject to prospective change by the FERC. Additionally, rate increases, changes to terms and conditions of service and contracts proposed by a regulated interstate pipeline may be protested and such actions can be delayed and may ultimately be rejected by the FERC. As of the filing of this Annual Report on Form 10-K, we and the MVP Joint

Venture currently hold authority from the FERC to charge and collect (i) “recourse rates,” which are the maximum rates an interstate pipeline may charge for its services under its tariff, (ii) “discount rates,” which are rates below the “recourse rates” and above a minimum level, (iii) “negotiated rates,” which involve rates that may be above or below the “recourse rates,” provided that the affected customers are willing to agree to such rates and that the FERC has approved the negotiated rate agreement, and (iv) market-based rates for some of our storage services from which we derive a small portion of our revenues. As of December 31, 2023, approximately 97% of our contracted firm transmission capacity was subscribed by customers under negotiated rate agreements under our tariff, rather than recourse, discount or market-based rate contracts. There can be no guarantee that we or the MVP Joint Venture will be allowed to continue to operate under such rates or rate structures for the remainder of those assets’ operating lives. Customers, the FERC or other interested stakeholders, such as state regulatory agencies, may challenge our or the MVP Joint Venture’s rates offered to customers or the terms and conditions of service included in our tariffs. Neither we nor the MVP Joint Venture have an agreement in place that would prohibit customers, including EQT or its affiliates, from challenging our or the MVP Joint Venture’s rates or tariffs. Any successful challenge against rates charged for our or the MVP Joint Venture’s transmission and storage services, as applicable, could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

Any changes to the FERC’s policies regarding the natural gas industry may have an impact on us, including the FERC’s approach to pro-competitive policies as it considers matters such as interstate pipeline rates and rules and policies that may affect rights of access to natural gas transmission capacity and transmission and storage facilities. The FERC and U.S. Congress may continue to evaluate changes in the NGA or new or modified FERC regulations or policies that may impact our or the MVP Joint Venture’s operations and affect our or the MVP Joint Venture’s ability to construct new facilities and the timing and cost of such new facilities, as well as the rates charged to our or the MVP Joint Venture’s customers and the services provided.

Our and the MVP Joint Venture’s significant construction projects generally require review by multiple governmental agencies, including state and local agencies, whose cooperation is important in completing the regulatory process on schedule. Any agency’s delay in the issuance of, or refusal to issue, authorizations or permits, issuance of such authorizations or permits with unanticipated conditions, or the loss of a previously-issued authorization or permit, for one or more of these projects may mean that we will not be able to pursue these projects or that they will be constructed in a manner or with capital requirements that we did not anticipate (as has been the case with our MVP project). Such delays, refusals, losses of permits, or resulting modifications to projects, certain of which we have experienced with respect to the MVP project and the originally contemplated MVP Southgate project, could materially and negatively impact the revenues and costs expected from these projects or cause us or our joint venture partners to abandon planned projects.

Failure to comply with applicable provisions of the NGA, the NGPA, federal pipeline safety laws and certain other laws, as well as with the regulations, rules, orders, restrictions and conditions associated with these laws, could result in the imposition of administrative and criminal remedies and civil penalties. For example, the FERC is authorized to impose civil penalties of up to approximately $1.5 million (adjusted periodically for inflation) per violation, per day for violations of the NGA, the NGPA or the rules, regulations, restrictions, conditions and orders promulgated under those statutes.

In addition, future federal, state or local legislation or regulations under which we or the MVP Joint Venture will operate may have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

Laws, regulations and other legal requirements applicable to our business also are constantly changing, and implementation of compliant processes in response to such changes could be costly and time consuming. As an example, designations of previously unprotected species as being endangered or threatened, or the designation of previously unprotected areas as a critical habitat for such species, has adversely affected and may in the future adversely affect our assets or projects. Additionally, as discussed under “Regulatory Environment” in “Item 1. Business” in Part I of this Annual Report on Form 10-K, federal and state governments and agencies, including states where we operate, have made advancing environmental justice a priority. A significant number of current environmental justice initiatives focus on enhancing public participation in permitting and other project development-related decisions. Our projects and the MVP Joint Venture’s projects have been, and in the future may be, the target of objections to permits before state and federal agencies and related litigation brought by individuals or advocacy organizations that are purporting to raise environmental justice issues. In addition, various federal and state agencies have increased their focus on, and resources devoted to, environmental justice and certain agencies, including EPA and DOJ, have sought out opportunities to address environmental justice issues through federal and state enforcement actions. Revised or additional laws, regulations or legal requirements (or interpretations thereof) that result in increased compliance costs, litigation or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, or affect our customers’ production and operations, could have a material adverse effect on our business, financial position, results of operations, liquidity and ability to pay dividends to our shareholders.

The DOT, acting through PHMSA, and certain state agencies certificated by PHMSA, have adopted regulations requiring pipeline operators to develop an integrity management program for transmission pipelines located where a leak or rupture could impact high population sensitive areas (also known as High Consequence Areas or HCAs) and newly defined Moderate Consequence Areas (MCAs), and an integrity management program for storage wells, unless the operator effectively demonstrates by a prescriptive risk assessment that these operational assets have mitigated risks that could affect these predefined areas, as applicable. The regulations require operators, including us, to perform ongoing assessments of pipeline and storage integrity; identify and characterize applicable threats to pipeline segments and storage wells that could impact population sensitive areas; confirm maximum allowable operating pressures; maintain and improve processes for data

collection, integration and analysis; repair and remediate facilities as necessary; and implement preventive and mitigating actions. In addition to population sensitive areas, PHMSA has recently adopted regulations extending existing design, operational and maintenance, and reporting requirements to onshore gathering pipelines in rural areas. Finally, new PHMSA regulations require operators of certain transmission pipelines to assess their integrity management and maintenance practices, comply with enhanced corrosion control and mitigation timelines, and follow new requirements for pipeline inspections following an extreme weather event or natural disaster.

The cost and financial impact of compliance will vary and depend on factors such as the number and extent of maintenance determined to be necessary as a result of the application of our integrity management programs, and such costs and financial impact could have a material adverse effect on us. Further, our pipeline and storage integrity management programs depend in part on inspection tools and methodologies developed, maintained, enhanced and applied, and certain testing conducted, by certain third parties, many of which are widely utilized within the natural gas industry. Advances in these tools and methodologies could identify potential and/or additional integrity issues for our assets. Consequently, we may incur additional costs and expenses to remediate those newly identified or potential issues, and we may not have the ability to timely comply with applicable laws and regulations. Additionally, pipeline and storage safety laws and regulations are subject to change and failures to comply with pipeline and storage safety laws and regulations, including changes in such laws and regulations or interpretations thereof that result in more stringent or costly safety standards, could have a material adverse effect on us. For more information on the laws, regulations and risks applicable to us, including risks associated with compliance with the Mega Rule, see “Regulatory Environment — Safety and Maintenance” under “Item 1. Business” in Part I of this Annual Report on Form 10-K.

We may, and joint ventures of which we are the operator could, as is the case with the MVP Joint Venture, become subject to consent orders and agreements relating to integrity matters. On October 3, 2023, PHMSA issued a consent order incorporating the terms of a consent agreement entered into by PHMSA and the Company as the operator of the MVP project (the MVP Consent Agreement). The MVP Consent Agreement resolves the Notice of Proposed Safety Order (NOPSO) that PHMSA issued to the Company on August 11, 2023, for the MVP project, without admission or denial of any of the allegations in the NOPSO. The MVP Consent Agreement outlines the steps being taken by the MVP Joint Venture to responsibly complete construction, including, among other things, enhancing MVP’s existing coating, remediation and inspection processes, mandating or accelerating certain previously planned MVP inline inspections, accelerating the regulatory timeline for conducting cathodic protection surveys, and implementing additional measures to assess cathodic protection following MVP full in-service. The MVP Joint Venture has been conducting surveys and analyses and submitting reports to PHMSA in compliance with the requirements of the consent agreement. Failure to comply with the terms of the MVP Consent Agreement could have adverse effects on our business, including, in the case of the MVP Consent Agreement, adverse effects regarding MVP project completion.

Our assets are primarily located in the Marcellus Shale fairway in southwestern Pennsylvania and northern West Virginia and the Utica Shale fairway in southeastern Ohio, and a substantial majority of the production that we receive from customers is produced from wells completed using hydraulic fracturing. Hydraulic fracturing is an important and commonly used process in the completion of oil and gas wells, particularly in unconventional resource plays like the Marcellus and Utica Shales.

The U.S. Congress has from time to time considered the adoption of legislation to provide for federal regulation of hydraulic fracturing, while a number of states, including those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. Some states, such as Pennsylvania, have imposed fees on the drilling of new unconventional oil and gas wells. Some states have elected, and other states could elect, to prohibit hydraulic fracturing altogether. In addition, there are regulations existing and proposed at the federal and state level that could indirectly limit or affect hydraulic fracturing. Also, certain local governments have adopted, and others may adopt, ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Further, several federal governmental agencies, including the EPA, as well as certain states, have conducted reviews and studies on the environmental aspects of hydraulic fracturing. The results of such reviews or studies have and could further spur initiatives to further regulate hydraulic fracturing.

The adoption of new laws, regulations, ordinances, or executive actions at the federal, state or local levels imposing more stringent restrictions on hydraulic fracturing could make it more difficult for our customers to complete natural gas wells,

increase customers’ costs of compliance and doing business, and otherwise adversely affect the hydraulic fracturing services they perform, which could negatively impact demand for our gathering, transmission and storage, or water services.

Furthermore, the tax laws, rules and regulations that affect our customers are subject to change. For example, in Pennsylvania legislation was proposed to impose a state severance tax on the extraction of natural resources, including natural gas produced from the Marcellus and Utica Shale formations, either in replacement of or in addition to the existing state impact fee. Pennsylvania’s legislature has not thus far advanced any of the severance tax proposals; however, severance tax legislation may continue to be proposed in future legislative sessions. Any such tax increase or change could adversely impact the earnings, cash flows and financial position of our customers and cause them to reduce their drilling in the areas in which we operate, which could negatively impact demand on our gathering, transmission and storage, and water services.

Prior to the EQM Merger, EQM was a publicly traded partnership and the anticipated after-tax economic benefit of an investment in our shares depended largely on EQM being treated as a partnership for federal income tax purposes, which requires that 90% or more of EQM’s gross income for every taxable year consist of qualifying income, as defined in Section 7704 of the Code. As a result of the EQM Merger, the requirements under Section 7704 of the Code are no longer applicable to EQM for taxable years beginning after December 31, 2020.

Despite the fact that EQM is a limited partnership under Delaware law and has not elected to be treated as a corporation for federal income tax purposes, it is possible, under certain circumstances, that the IRS could determine on audit for taxable years prior to January 1, 2021 for EQM to be treated as a corporation for federal income tax purposes. For example, EQM would be treated as a corporation if the IRS determined that less than 90% of EQM’s gross income for any such taxable year consisted of qualifying income within the meaning of Section 7704 of the Code.

If EQM was treated as a corporation for federal income tax purposes for any taxable year prior to January 1, 2021, EQM would be required to pay federal income tax on its taxable income at the corporate tax rate applicable to the relevant tax year and would likely pay state income taxes at varying rates. Distributions to us after the Separation Date would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to us. Treatment of EQM as a corporation could result in a material reduction in the anticipated cash flow in the year of the payment to the IRS, potentially causing, among other things, a substantial reduction in the value of our shares.

Pursuant to the Bipartisan Budget Act of 2015, if the IRS makes audit adjustments to EQM’s income tax return for tax years beginning after 2017, the IRS (and some states) may assess and collect any resulting taxes (including any applicable interest and penalties) directly from EQM. EQM will have a limited ability to shift any such tax liability to its general partner and unitholders, including us, in accordance with their interests in EQM during the year under audit, but there can be no assurance that EQM will be able to do so under all circumstances, or that EQM will be able to effect corresponding shifts in state income or similar tax liability resulting from the IRS adjustment in states in which EQM does business in the year under audit or in the adjustment year. As a result of the EQM Merger, we own all of the EQM common units. If EQM makes payments of taxes, penalties and interest resulting from audit adjustments with respect to tax periods beginning after 2017 and before 2021, we and potentially former unitholders may be required to reimburse it for such payment or, if EQM is required to bear such payments, such payments could have a material adverse effect on our business, financial position, results of operations, liquidity and ability to pay dividends to our shareholders.

In the event the IRS makes an audit adjustment to EQM’s income tax returns and EQM does not or cannot shift the liability to its unitholders in accordance with their interests in EQM during the year under audit, EQM will generally have the ability to request that the IRS reduce the determined underpayment by reducing the suspended passive loss carryovers of EQM’s unitholders (without any compensation from EQM to such unitholders), to the extent such underpayment is attributable to a net

decrease in passive activity losses allocable to certain partners. Such reduction, if approved by the IRS, will be binding on any affected unitholders.

The market price of our common stock has experienced substantial price volatility in the past and may continue to do so due to a number of factors, including the MVP project, some of which may be beyond our control. General market fluctuations, industry factors, such as climate change-related physical and transitional risks, and general economic and political conditions and events, such as economic slowdowns or recessions, as well as factors specific to our business (including the status of and cost to construct the MVP project and perceptions regarding our growth opportunities), have, as applicable, caused and could also continue to cause our stock price to decrease regardless of operating results. If we fail to meet expectations related to future growth, profitability, cash dividends, de-levering, strategic transactions or other market expectations, the market price of our common stock may decline significantly. Additionally, our stock price may be adversely affected by transactions in our common stock by significant shareholders. A reduced stock price affects, among other things, our cost of capital and could affect our ability to execute future strategic transactions, as well as increases opportunities for investor activism or unsolicited third-party activity affecting us.

We are not required to declare and pay dividends to our common shareholders. Our Board previously has reduced, and in the future may decide to further reduce, the amount of the cash dividend that we pay on our common stock. Our Board may also decide not to declare any dividends in the future. Although we have in the past paid regular cash dividends, any payment of future dividends will be at the sole discretion of our Board and will depend upon many factors, including the Pennsylvania Business Corporation Law (PBCL), the financial condition, earnings, liquidity and capital requirements of our operating subsidiaries, covenants associated with certain debt obligations, legal requirements, our leverage, regulatory constraints and other factors deemed relevant by our Board. We also may not pay any dividends on any junior securities, including any shares of our common stock, prior to paying the quarterly dividends payable to the holders of Equitrans Midstream Preferred Shares, including any previously accrued and unpaid dividends.

Our shareholders’ percentage of ownership in us may be diluted because of equity issuances for acquisitions, capital market transactions or otherwise, including, without limitation, equity awards that we may grant to our directors, officers, and employees. Our Human Capital and Compensation Committee and our Board have authority to grant share-based awards to our employees under employee benefit plans and, from time to time, we issue share-based awards to our employees under our employee benefit plans. Such awards will have a dilutive effect on our earnings per common share, which could adversely affect the market price of our common stock. Equity issuances may have a dilutive effect on our earnings per share, which could adversely affect the market for and the market price of our stock, and have a dilutive effect on our shareholders’ ownership interests in us.

In addition, our Second Amended and Restated Articles of Incorporation authorize us to issue, without the approval of our shareholders, one or more classes or series of preferred stock that have such designations, powers, preferences and relative, participating, optional and other special rights, including preferences over our common stock respecting dividends and distributions, as our Board generally may determine. The terms of one or more classes or series of preferred stock could dilute the voting power or reduce the value of our common stock. Similarly, the repurchase or redemption rights or liquidation preferences we could assign to holders of preferred stock could affect the residual value of our common stock.

Our Second Amended and Restated Articles of Incorporation and Fifth Amended and Restated Bylaws contain provisions that could have the effect of rendering more difficult or discouraging an acquisition of us deemed undesirable by our Board. These include provisions:

These provisions, alone or together, could deter or delay hostile takeovers, proxy contests and changes in control or management of us. As a Pennsylvania corporation, we are also subject to provisions of Pennsylvania law, including certain provisions of Chapter 25 of the PBCL, which, among other things, requires enhanced shareholder approval for certain transactions between us and a shareholder who is a party to the transaction or is treated differently from other shareholders and also prevents persons who become the beneficial owner of shares representing 20% or more of our voting power from engaging in certain business combinations without approval of our Board, and in some cases preventing consummation of the transaction for at least five years.

Any provision of our Second Amended and Restated Articles of Incorporation, Fifth Amended and Restated Bylaws or Pennsylvania law that has the effect of delaying or deterring a change in control of us could limit the opportunity for our shareholders to receive a premium for their shares of our common stock and also could affect the price that some investors are willing to pay for our common stock.

Our Fifth Amended and Restated Bylaws provide that, unless our Board otherwise determines, the state and federal courts sitting in the judicial district of the Commonwealth of Pennsylvania, County of Allegheny, will be the sole and exclusive forum for any derivative action or proceeding brought on behalf of us, any action asserting a claim of breach of a fiduciary duty owed by any director or officer or other employee of ours to us or our shareholders, any action asserting a claim against us or any director or officer or other employee of us arising pursuant to any provision of the PBCL or our Second Amended and Restated Articles of Incorporation and Fifth Amended and Restated Bylaws or any action asserting a claim against us or any director or officer or other employee of ours governed by the internal affairs doctrine. The choice of forum provision set forth in our Fifth Amended and Restated Bylaws does not apply to actions arising under the Securities Act or the Exchange Act.

When applicable, this exclusive forum provision may limit the ability of our shareholders to bring a claim in a judicial forum that such shareholders find favorable for disputes with us or our directors or officers, which may discourage such lawsuits against us and our directors and officers. Alternatively, if a court outside of Pennsylvania were to find this exclusive forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings described above, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, results of operations and financial condition.

Equitrans Midstream Preferred Shares present a number of risks to current and future holders of our common stock, including a preference in favor of holders of Equitrans Midstream Preferred Shares in the payment of dividends on our common stock, the risk of dilution occurring as a result of the conversion of the Equitrans Midstream Preferred Shares into our common stock and

the ability of the holders of the Equitrans Midstream Preferred Shares to vote with the holders of our common stock on most matters, as well as the risk that the holders of the Equitrans Midstream Preferred Shares will have certain other class voting rights with respect to any amendment to our organizational documents that would be adverse (other than in a de minimis manner) to any of the rights, preferences or privileges of the Equitrans Midstream Preferred Shares.

We are party to a Registration Rights Agreement with certain holders of the Equitrans Midstream Preferred Shares pursuant to which, among other things, we gave the investors certain rights to require us to file and maintain one or more registration statements with respect to the resale of the Equitrans Midstream Preferred Shares and the shares of our common stock that are issuable upon conversion of the Equitrans Midstream Preferred Shares. In July 2023, pursuant to this Registration Rights Agreement, we filed a registration statement with the SEC to register up to 30,018,446 Equitrans Midstream Preferred Shares and up to 30,018,446 shares of our common stock that are issuable upon conversion of the Equitrans Midstream Preferred Shares held by such certain investors party to the Registration Rights Agreement.

It was a condition to the Distribution that (i) a private letter ruling from the IRS regarding the qualification of the Distribution, together with certain related transactions, as a transaction that is generally tax-free for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code and certain other U.S. federal income tax matters relating to the Separation and Distribution shall not have been revoked or modified in any material respect and (ii) EQT received an opinion of counsel with respect to certain tax matters relating to the qualification of the Distribution, together with certain related transactions, as a transaction described in Sections 355 and 368(a)(1)(D) of the Code. The IRS private letter ruling is based upon and relies on, and the opinion of counsel is based upon and relies on, among other things, various facts and assumptions, as well as certain representations, statements and undertakings of EQT and us, including those relating to the past and future conduct of EQT and us. If any of these representations, statements or undertakings is, or becomes, inaccurate or incomplete, or if any representations or covenants contained in any of the Separation-related agreements and documents or in any documents relating to any IRS private letter ruling or opinion of counsel are breached, such IRS private letter ruling and/or opinion of counsel may be invalid and the conclusions reached therein could be jeopardized.

Notwithstanding receipt of the IRS private letter ruling and opinion of counsel, the IRS could determine that the Distribution and/or certain related transactions should be treated as taxable transactions for U.S. federal income tax purposes if it determines that any of the representations, assumptions or undertakings upon which such IRS private letter ruling or the opinion of counsel was based are false or have been violated. In addition, the IRS private letter ruling does not address all of the issues that are relevant to determining whether the Distribution, together with certain related transactions, continues to qualify as a transaction that is generally tax-free for U.S. federal income tax purposes, and the opinion of counsel represented the judgment of such counsel and is not binding on the IRS or any court and the IRS or a court may disagree with the conclusions in any opinion of counsel. Accordingly, notwithstanding receipt of an IRS private letter ruling or opinion of counsel, there can be no assurance that the IRS will not assert that the Distribution and/or certain related transactions do not qualify for the intended tax treatment or that a court would not sustain such a challenge. In the event the IRS were to prevail with such challenge we, EQT, and our respective shareholders could be subject to material U.S. federal income tax liability.

Even if the Distribution otherwise qualifies as generally tax-free for U.S. federal income tax purposes under Section 355 and Section 368(a)(1)(D) of the Code, it would result in a material U.S. federal income tax liability to EQT (but not to its shareholders) under Section 355(e) of the Code if one or more persons acquire, directly or indirectly, a 50-percent or greater interest (measured by either vote or value) in EQT’s stock or in the stock of us as part of a plan or series of related transactions that includes the Distribution, and we may be required to indemnify EQT for any such liability under the tax matters agreement entered into by EQT and us in connection with the Distribution. The process for determining whether an acquisition is part of a plan under these rules is complex, inherently factual in nature and subject to a comprehensive analysis of the facts and circumstances of the particular case. Notwithstanding the IRS private letter ruling and opinion of counsel described above, a sufficient change in ownership of EQT or our common stock may occur which could result in a material tax liability to EQT.

Under the tax matters agreement that EQT entered into with us, we may be required to indemnify EQT against any additional taxes and related amounts resulting from (i) an acquisition of all or a portion of our equity securities or assets, whether by merger or otherwise (and regardless of whether we participated in or otherwise facilitated the acquisition), (ii) other actions or failures to act by us or (iii) any of our representations, covenants or undertakings contained in any of the Separation-related

agreements and documents or in any documents relating to the IRS private letter ruling or the opinion of counsel being incorrect or violated. Any such indemnity obligations could be material.

If the IRS were to successfully assert that the EQM Merger or certain share purchases from EQT in 2020 resulted in the Distribution and/or certain related transactions being treated as taxable transactions to EQT for U.S. federal income tax purposes, we may be required to indemnify EQT for such taxes and related amounts.

There are several significant areas where the liabilities of EQT may become our obligations. For example, under the Code and the related rules and regulations, each corporation that was a member of the EQT consolidated U.S. federal income tax return group (EQT Tax Group) during a taxable period or portion of a taxable period ending on or before the effective date of the Distribution is jointly and severally liable for the U.S. federal income tax liability of the EQT Tax Group for that taxable period. Consequently, if EQT is unable to pay the consolidated U.S. federal income tax liability for a pre-Separation period, we could be required to pay the amount of such tax, which could be substantial and in excess of the amount allocated to us under the tax matters agreement. Other provisions of federal law establish similar liability for other matters, including laws governing tax-qualified pension plans, as well as other contingent liabilities.

None.

Due to the critical nature of our business to the U.S. economy and national energy security and the continuous threat of cyberattacks, we regard cybersecurity as a top tier enterprise risk. Cybersecurity is integrated into our enterprise risk management program, which includes quarterly technology and cybersecurity risk assessments. We use the results of the technology and cybersecurity risk assessments for risk-based decision making to determine actions and priorities for our cybersecurity program. The technology and cybersecurity risk assessment process includes an objective, risk-ranking process; documented mitigation activities; and action plans for those risks requiring additional mitigation. These activities consider safety implications, operational disruptions, and business and financial impacts. As part of the cybersecurity program, we regularly obtain threat intelligence from various sources, which sources originate from private, commercial, and independent entities. In addition, our IT leadership routinely conducts risk quantification, simulations, and assessment exercises. We regularly engage with relevant government agencies to report and share certain security information enabling us to benchmark our capabilities, establish appropriate program targets, and adapt to emerging cybersecurity issues.

To manage our cybersecurity risk, we practice cyber hygiene through, among other measures, identity and access management, vulnerability and patch management, and asset management programs. We also segment our informational and operational technologies, and leverage network micro-segmentation and combine this practice with zero-trust security concepts. Operationally, we continuously monitor for cyber intrusions and augment our internal resources and capabilities with third-party service providers. Multiple security technologies are employed to protect our systems, applications, and data, including

next generation firewalls, multi-factor authentication and access controls, and endpoint detection and response solutions. We have integrated our cloud-hosted services with our security operations center and have implemented measures aimed at securing our remote workforce. We measure our cybersecurity practices against the National Institute of Standards and Technology Cybersecurity Framework, relevant industry standards, and government regulations. We routinely engage independent third-party security firms to exercise and assess our cybersecurity capabilities.

Our information technology governance, including cybersecurity, is documented through written policies, procedures, guidelines, and standard operating procedures. All of our employees are required to undergo quarterly cybersecurity training. This training includes cybersecurity policies, cyber threats, and incorporating best practices into daily routines. Contractors and vendors that have access to our data, devices, or services are required to complete cybersecurity training prior to receiving access. Employees, vendors, and contractors with access to our operational technology network are required to undergo additional training specific to operational technology interactions. We maintain a Supplier Code of Conduct that is provided to our providers of materials and services during the onboarding process and that conveys our expectations regarding use and access requirements when using our technology resources.

We also manage cybersecurity risk through incident response strategies. We employ a fault-tolerant, highly available architecture and network segmentation as part of our containment strategy. We do not solely rely on architecture to ensure continuity and containment, and we employ additional technologies including, but not limited to, automated account disabling, automated device quarantining, network segment-isolation scripts, and cyber kill chain runbooks. We have implemented an Enterprise Data Backup Policy, which includes, among other activities, offsite backups, intra-day recovery points, and routine restoration of critical data. We use infrastructure-as-code to enable recovery of virtualized environments and employ data replication across multiple operating regions. We routinely exercise our recovery capabilities. Our Cybersecurity Incident Response Plan establishes a framework to manage the life cycle of a cyber event. Additionally, our Enterprise Crisis Management Plan provides a structure to assemble an enterprise crisis team in the event of a potential cyber related crisis. The crisis response team, including our Chief Information Officer (CIO), is responsible for managing the channels of communication pursuant to our Crisis Management Plan. This notification includes the notification or reporting of any significant cyber incidents to executive management. We periodically conduct cyber incident drills that include, as applicable, members of our Board of Directors, executives, certain business stakeholders, and legal and security partners, as necessary.

Given the importance to us of our cybersecurity program, in April 2022, our Board elected to exercise direct oversight of cybersecurity matters, rather than acting through its committees. The Board, as well as separately our executive management, receives, and has the opportunity to ask questions and raise discussion points regarding, management reports from the CIO and Senior Director of Cybersecurity and Network Operations on cybersecurity matters, as needed and no less than quarterly throughout the year, which reports include items such as cybersecurity updates, cybersecurity operational results, and audit findings. In addition, the Board and executive management receives and reviews the results of our cybersecurity risk and capabilities assessment on an annual basis.

The cybersecurity program is managed by our CIO and our Senior Director of Cybersecurity and Network Operations and reviewed and monitored by executive management, with oversight from the Board. Our CIO has significant expertise and more than 30 years of experience in information technology and cybersecurity including cloud technologies and reports to our Executive Vice President & Chief Legal Officer. Our Senior Director of Cybersecurity and Network Operations has more than two decades of experience in the fields of information technology and cybersecurity and holds cybersecurity certifications, including the Certified Information Systems Security Professional, Certified Cloud Security Professional, and GIAC Information Security Professional certifications. The CIO and Senior Director of Cybersecurity and Network Operations meet regularly with each other and members of their team to discuss cybersecurity threats, capabilities and program strategy. We have built in incident workflows that automatically provide notifications and escalate cybersecurity incidents. During an incident, the CIO acts as the incident commander and the Senior Director of Cybersecurity and Network Operations acts as operations section chief, working together to provider supervision over incident response.

The Company leases its corporate headquarters office in Canonsburg, Pennsylvania.

The Company's real property falls into two categories: (i) parcels that it owns in fee and (ii) parcels in which its interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for the Company's operations. Certain lands on which the Company's pipelines and facilities are located are owned by the Company in fee title, and the Company believes that it has satisfactory title to these lands in all material respects. Other lands on which the Company's pipelines and facilities are located are held pursuant to surface leases or easements between the Company, as lessee or grantee, and the respective fee owners of the lands, as lessors or grantors. The Company has held, leased or owned many of these lands for many years without any material challenge known to the Company relating to the title to the land upon which the assets are located, and the Company believes that it has satisfactory leasehold estates, easement interests or fee ownership to such lands in all material respects. The Company believes that it has satisfactory title to all of its material leases, easements, rights-of-way, permits and licenses in all material respects, and the Company has no knowledge of any material challenge to its title to such assets or their underlying fee title.

See Part I, "Item 1. Business" of this Annual Report on Form 10-K for a discussion of the Company's business segments relevant to its property holdings and map of the Company's operations.

From time to time, various legal and regulatory claims, investigations and proceedings are pending or threatened against the Company and its subsidiaries. While to the extent applicable the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims, investigations and proceedings. The Company accrues legal and other direct costs related to loss contingencies when incurred. The Company establishes reserves whenever it believes a reserve is appropriate for pending matters. Furthermore, after consultation with counsel and considering the availability, if any, of insurance, the Company believes, although no assurance can be given, that the ultimate outcome of any matter currently pending against it or any of its consolidated subsidiaries as of the filing of this Annual Report on Form 10-K will not materially adversely affect its business, financial condition, results of operations, liquidity or ability to pay dividends to its shareholders.

On December 29, 2022, the PHMSA issued the Company a Notice of Proposed Safety Order that included proposed remedial requirements related to the Rager Mountain natural gas storage field incident, including, but not limited to, completing a root cause analysis. The Company addressed certain proposals in advance of an order from the agency. These efforts included conducting testing, evaluating other wells at the Rager field and hiring a third-party specialist firm to undertake a root cause analysis, and subsequently on May 26, 2023, the PHMSA issued a consent order to the Company incorporating the terms of a consent agreement between the parties, which, among other things, required the completion of a root cause analysis and a remedial work plan, and specified that the Company may not resume injection operations at the Rager Mountain facility until authorized by the PHMSA. As discussed in “Transmission Results of Operation” in Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" of this Annual Report on Form 10-K, in August 2023, the Company submitted a root cause analysis to the PHMSA in accordance with the consent order and later submitted a remedial work plan and, following completion of all actions in its remedial work plan, an injection plan to the PHMSA seeking authority to resume injections at Rager Mountain using all wells except three, which remain disconnected. On October 2, 2023, the PHMSA approved the Company’s injection plan. The Company began injections at Rager Mountain on October 5, 2023, subject to certain pressure restrictions and other requirements specified in the consent agreement between the PHMSA and the Company. On November 16, 2023, the PHMSA issued a letter to the Company approving the Company’s request to remove all pressure restrictions at the Rager Mountain facility. The Company plans to continue working with the PHMSA, pursuant to the consent order, regarding the remaining three wells.

If additional penalties are pursued and ultimately imposed related to the Rager Mountain natural gas storage field incident, the penalties, individually and/or in the aggregate, are expected to result in monetary sanctions in excess of $300,000. While the Company does not believe that penalties, if imposed, will have a material adverse impact on the Company's financial condition, results of operations or liquidity, there can be no assurance as of the filing of this Annual Report on Form 10-K regarding the scope of potential (or ultimately actual) financial or other impacts to the Company as a result of the Rager Mountain natural gas storage field incident.

There remain certain legal and regulatory matters relevant to the MVP project, the outcome of which could have adverse effects with respect to the project and consequently the Company, including matters pending with the U.S. Court of Appeals for the District of Columbia (D.C. Circuit) described below:

December 31, 2023. Prior to joining Equitrans Midstream, Mr. Moore was general counsel of PennTex Midstream Partners, LP, a publicly traded master limited partnership, from 2014 through 2017. From March 2018 to April 2019, Mr. Moore served as special projects counsel to UGI Corporation.

All executive officers have executed agreements with the Company and serve at the pleasure of the Board. Officers are elected annually to serve during the ensuing year or until their successors are elected and qualified, or until their death, resignation or removal.

Equitrans Midstream common stock trades on the NYSE under the symbol "ETRN".

As of January 31, 2024, there were 1,626 shareholders of record of Equitrans Midstream common stock.

On January 23, 2024, the Board declared cash dividends for the fourth quarter of 2023 of $0.15 per common share and $0.4873 per Equitrans Midstream Preferred Share, which dividends were paid on February 14, 2024 to shareholders of record at the close of business on February 6, 2024.

See Part III, “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” of this Annual Report on Form 10-K for information relating to the Company’s equity compensation plans.

The Company did not have any sales of unregistered securities registered under Section 12 of the Exchange Act during the three months ended December 31, 2023.

The following table sets forth the Company's repurchases of equity securities registered under Section 12 of the Exchange Act that occurred during the three months ended December 31, 2023.

(a) Reflects shares withheld by the Company to pay taxes upon vesting of restricted stock.

As part of implementing the Company's succession plan, on January 1, 2024, Mr. Thomas F. Karam stepped down as Chief Executive Officer of the Company and Diana M. Charletta, the former President and Chief Operating Officer, became President and Chief Executive Officer.

The Company recognizes that the long-term interests of shareholders are served by managing ESG matters important to the Company’s stakeholders and working to be resilient and appropriately positioned in any environment, including a lower-carbon economy. The Company embraces working to conduct business in a socially responsible and ethical manner by respecting all stakeholders, and is focused on identifying and executing on ESG and sustainability initiatives while further integrating corporate responsibility and ESG concerns into its business strategy and decision-making throughout the organization. The Company also is committed to continuing to operate with integrity, accountability and transparency. As a result, the Company anticipates that it will continue to prudently allocate capital resources to ESG and sustainability initiatives in the future, which may include at increasing levels, which the Company believes will benefit the sustainability of the Company's business and help to create value.

The Company believes that natural gas will remain a significant component of the global and national energy complex and will play a vital role in the transformation to a lower-carbon economy, notwithstanding increased demand for alternative energy sources and negative sentiment with respect to natural gas, including natural gas infrastructure, from certain actors. Further, the Company believes that continued natural gas production and infrastructure growth are directly supportive of the United States' energy security, as evidenced by the historic inclusion of provisions mandating the completion of the MVP project in the Fiscal Responsibility Act of 2023. The Company also acknowledges the reality and risks of climate change as a critical current issue and, as an energy infrastructure company, recognizes the ongoing developments and risks surrounding climate change. As a result, the Company is focused on long-term sustainable performance, such as continuing to proactively pursue climate change mitigation aspirations while also balancing the need to deliver reliable, safe, and affordable natural gas energy in the United States now and in the future.

The Company is focused on executing on sustainability initiatives while further integrating sustainability-focused risks and opportunities into the Company’s strategic and capital spending decision processes. In 2023, the Company focused primarily on developing the appropriate strategy and building the requisite programs and plans for achieving its GHG reduction goals. In January 2023, the Company announced its status as a founding member of the newly formed Appalachian Methane Initiative (AMI), a coalition of regional natural gas operators committed to further enhancing methane monitoring throughout the Appalachia Basin and facilitating additional methane emissions reduction in the region. Additionally, the Company’s GHG Committee developed a portfolio of 2024 capital projects that includes avoiding or eliminating methane emissions from both certain fixed and event-based sources. Further, the Company finalized its GHG Management program, providing the roadmap and accounting protocols for pursuing achievement of and reporting on progress towards its aspirational emissions targets. Additionally, aspects of the Company's compensation structure reflect sustainability-oriented goals and developments. For example, the Human Capital and Compensation Committee of the Board determined to include the completion of certain scenario analyses under the Task Force on Climate-Related Financial Disclosures framework, and the development of a related publishable report, as a metric in the Company’s 2023 short-term incentive compensation program applicable to all employees,

including executives. The Company expects to continue to pursue strategic sustainability initiatives as appropriate, including with respect to climate change, and to incur costs and capital expenditures to do so. Costs and expenses associated with sustainability and ESG matters could be material.

Operating segments are revenue-producing components of an enterprise for which separate financial information is produced internally and is subject to evaluation by the chief operating decision maker in deciding how to allocate resources. Headquarters costs consist primarily of certain unallocated corporate expenses and transaction costs, as applicable. Net interest expense, loss on extinguishment of debt, components of other income (expense), net, and income tax expense (benefit) are managed on a consolidated basis. The Company has presented each segment's operating income (loss), other income (expense), net, equity income, impairment of equity method investment and various operational measures, as applicable, in the following sections. Management believes that the presentation of this information is useful to management and investors regarding the financial condition, results of operations and trends and uncertainties of its segments. The Company has reconciled each segment's operating income (loss) to the Company's consolidated operating income (loss) and net income (loss) in Note 3 to the consolidated financial statements.

Gathering operating expenses increased by $28.3 million for the year ended December 31, 2023 compared to the year ended December 31, 2022. Selling, general and administrative expenses increased by $31.1 million primarily due to higher incentive compensation of $29.2 million, including $12.3 million associated with the MVP PSU Program that included the impact of a cumulative catch-up since the inception of the award. Operating and maintenance expenses decreased by $4.3 million primarily due to lower operating expenses associated with the divestiture of the regulated low pressure gathering assets in June 2023 and lower repairs and maintenance expenses, partially offset by higher personnel costs and higher property taxes. Depreciation expense increased by $1.5 million as a result of additional assets placed in-service.

See "Overview of the Company and Operations" in Part 1, "Item 1. Business" of this Annual Report on Form 10-K for discussions of the EQT Global GGA, and the transactions related thereto, including periodic gathering MVC fee declines and, additionally, discussion that in connection with MVP full in-service the EQT Global GGA provides for more significant potential gathering MVC fees declines in certain contract years. Firm reservation fee revenues under the Company’s Hammerhead gathering agreement with EQT are expected to contribute to an increase in the Company’s firm reservation fee revenues following achievement of the Hammerhead pipeline full commercial in-service in conjunction with full MVP in-service. However, the percentage of the Company's operating revenues that are generated by firm reservation fees may vary year to year depending on various factors, including customer volumes and the rates realizable under the Company’s contracts, including the EQT Global GGA. See also "Commodity Price Risk" in Part II, "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" of this Annual Report on Form 10-K for additional information on factors that could affect the Company's operating revenues. Also, see Note 8 for further discussion on the MVP PSU Program.

Transmission operating revenues increased by $38.6 million for the year ended December 31, 2023 compared to the year ended December 31, 2022. Firm reservation fee revenues decreased by $9.4 million primarily due to lower contracted capacity payments resulting from the one-time contract buyout that occurred during the first quarter of 2023. Volumetric-based fee revenues increased by $48.0 million primarily as a result of a one-time contract buyout by a customer of approximately $23.8 million and higher volumes in excess of firm capacity contracts.

Operating expenses increased by $41.9 million for the year ended December 31, 2023 compared to the year ended December 31, 2022. Operating and maintenance expense increased $21.8 million primarily due to operational efficiencies associated with operating activities with the Gathering segment for replenishment gas on the regulated low pressure gathering assets which were divested in June 2023, increased personnel costs and expenses associated with the Rager Mountain natural gas storage field incident. Selling, general and administrative expenses increased by $19.7 million resulting primarily from higher incentive compensation of $12 million, including $4.7 million associated with the MVP PSU Program that included the impact of a cumulative catch-up since the inception of the award, an increased reserve for bad debt expense and higher professional fees.

Regarding the Rager Mountain natural gas storage field incident, the root cause analysis, which was conducted by an independent, third-party company with expertise in reservoir management and well and corrosion engineering, was submitted to the PHMSA in August 2023, which root cause analysis indicated that the direct cause of the venting from the relevant Rager Mountain facility storage well (well #2244) was due to corrosion caused by the infiltration of water, oxygen and debris into the well's annulus, and such corrosion resulted in a failure of the well casing. Based on results of an inventory verification test conducted after the venting incident was resolved, the Company’s initial gas loss estimate for well #2244 was approximately 1.29 Bcf. Following completion of the root cause analysis, the cumulative gas loss was determined to be approximately 1.164 Bcf, approximately 1.037 Bcf of which was vented to the atmosphere and roughly 0.127 Bcf was diverted to and contained within formation(s) located at approximately 1,800’ and/or 3,000’ below ground. Post-incident workstreams related to the safe and environmentally responsible operation of the Rager Mountain facility and other storage fields are ongoing.

Equity income increased by $175.0 million for the year ended December 31, 2023 compared to the year ended December 31, 2022 due to the increase in the MVP Joint Venture's AFUDC on the MVP project resulting from the resumption of growth construction activities in 2023. Following MVP full in-service, the Company's equity income will be primarily derived from 20-year firm reservation contracts for the MVP project.

Water operating revenues increased by $18.0 million for the year ended December 31, 2023 compared to the year ended December 31, 2022. Firm reservation fee revenues increased by $5.3 million primarily as a result of increased revenues due to a full year of ARCs associated with the 2021 Water Services Agreement. Volumetric-based fee revenues increased by $12.7 million primarily due to higher volumes.

Water operating expenses increased by $19.3 million for the year ended December 31, 2023 compared to the year ended December 31, 2022. Selling, general and administrative expense increased by $7.4 million primarily due to a contract asset write-down. Operating and maintenance expense increased by $5.9 million due to higher mixed-use water storage expenses related to storage facilities placed in-service during the year ended December 31, 2023. Depreciation expense increased $6.0 million due to additional assets placed in-service.

The Company’s volumetric-based water services are directly associated with producers’ well completion activities and fresh and produced water needs (which are primarily driven by horizontal lateral lengths and the number of completion stages per well). Therefore, the Water volumetric operating results traditionally fluctuate from year-to-year in response to producers’ well completion activities.

Other income (expense), net, decreased $10.6 million for the year ended December 31, 2023 compared to the year ended December 31, 2022. The decrease was primarily due to a $1.5 million unrealized gain on derivative instruments during the year ended December 31, 2023 as compared to a $9.6 million unrealized gain on derivative instruments during the year ended December 31, 2022, and a $3.7 million gain on the sale of non-core gathering assets during the year ended December 31, 2022, partially offset by higher sublease income. The decrease in unrealized gains on derivative instruments was primarily due to changes in timing and probability-weighted assumptions regarding MVP project completion and changes in NYMEX Henry Hub natural gas futures prices associated with the Henry Hub cash bonus payment provision.

During the year ended December 31, 2022, the Company incurred a loss on extinguishment of debt of approximately $24.9 million related to the 2022 Tender Offers (as defined in Note 9) for Senior Notes and open market repurchase premiums and fees, and write off of the respective unamortized discounts and financing costs associated with the purchase of portions of 2023, 2024 and 2025 Notes in such Tender Offers.

Net interest expense increased by $32.6 million for the year ended December 31, 2023 compared to the year ended December 31, 2022 primarily due to increased interest rates and borrowings under the revolving credit facilities and interest on the 2022 Senior Notes (as defined in Note 9), partially offset by the impact of the 2022 Tender Offers and the redemption of the 2023 Notes effected in June 2023.

See also Note 9 and Note 15 to the consolidated financial statements for a discussion of certain of the Company's outstanding debt.

See Note 12 to the consolidated financial statements for an explanation of the changes in income tax expense and effective tax rate for the year ended December 31, 2023 compared to the year ended December 31, 2022.

Net income attributable to noncontrolling interest decreased $2.7 million for the year ended December 31, 2023 compared to the year ended December 31, 2022 primarily as a result of lower net income on Eureka Midstream.

See "Investing Activities" and "Capital Requirements" under "Capital Resources and Liquidity" for a discussion of capital expenditures and capital contributions.

The Company's strategically located and integrated assets overlay core acreage in the Appalachian Basin. The location of the Company's assets allows its producer customers to access major demand markets in the U.S. The Company is one of the largest natural gas gatherers in the U.S., and its largest customer, EQT, was one of the largest natural gas producers in the U.S. based on average daily sales volumes as of December 31, 2023 and EQT's public senior debt had investment grade credit ratings from Standard & Poor's Global Ratings (S&P), Fitch Ratings (Fitch) and Moody's Investors Service (Moody's) as of that date. For the year ended December 31, 2023, approximately 70% of the Company's operating revenues were generated from firm reservation fee revenues. Generally, the Company is focused on utilizing contract structures reflecting long-term firm capacity, MVC or ARC commitments which are intended to provide support to its cash flow profile. The percentage of the Company's operating revenues that are generated by firm reservation fees (as well as the Company's revenues generally) may vary year to year depending on various factors, including customer volumes and the rates realizable under the Company’s contracts, including the EQT Global GGA which provides for periodic gathering MVC fee declines through January 1, 2028 (with the fee then remaining fixed throughout the remaining term). Additionally, as discussed in "Overview of the Company and Operations" in Part 1, "Item 1. Business", in connection with MVP full in-service the EQT Global GGA provides for more significant potential gathering MVC fee declines in certain contract years.

The Company's principal strategic aim is to achieve greater scale and scope, enhance the durability of its financial strength and to continue to work to position itself for a lower carbon economy.

The Company's standalone strategy reflects its continued pursuit of organic growth projects, including completing and placing in service the MVP, focusing on identifying opportunities to use its existing assets to deepen and grow its customer relationships at optimized levels of capital spending and taking into account the Company’s leverage, and continuing to prudently invest resources in its sustainability-oriented initiatives. The Company’s strategy also reflects its continued focus on achieving a strong balance sheet, and given the Company’s size, operating footprint and other factors considering inorganic opportunities, such as to extend the Company’s operations’ into the southeast United States and new, key demand markets, such as the Gulf of Mexico LNG export market.

As part of its approach to organic growth, the Company is focused on its projects and assets outlined in "Developments, Market Trends and Competitive Conditions" in Part I, "Item 1. Business" of this Annual Report on Form 10-K, many of which are supported by contracts with firm capacity, MVC or ARC commitments.

For discussion of the Company's commercial relationship with EQT and related considerations, including risk factors, see Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K.

For a discussion of capital expenditures, see "Capital Requirements" under "Capital Resources and Liquidity" below.

The following table is a summary of the cash flows by activity for the years ended December 31, 2023, 2022 and 2021, respectively.

Net cash flows provided by operating activities increased approximately $170.3 million for the year ended December 31, 2023 as compared to the year ended December 31, 2022. The increase was primarily driven by the payment of the EQT Cash

Net cash flows used in investing activities increased by $503.0 million for the year ended December 31, 2023 as compared to the year ended December 31, 2022. The increase was primarily due to an increase in capital contributions to the MVP Joint Venture. See “Capital Requirements” below for a discussion of forecasted 2024 capital expenditures and capital contributions to the MVP Joint Venture.

Net cash flows provided by financing activities were $245.0 million for the year ended December 31, 2023 as compared to net cash flows used in financing activities of $345.5 million for the year ended December 31, 2022. For the year ended December 31, 2023, the primary source of financing cash flows were proceeds from borrowings under the revolving credit facilities, while the primary uses of financing cash flows were repayments on borrowings under the revolving credit facilities, the payments of dividends to shareholders, the redemption of the 2023 Notes and distributions paid to noncontrolling interest. For the year ended December 31, 2022, the primary uses of financing cash flows were the purchase of certain tranches of EQM's outstanding long-term indebtedness pursuant to the 2022 Tender Offers and an open market purchase, repayments on borrowings under the revolving credit facilities, and the payments of dividends to shareholders, while the primary source of financing cash flows were the issuance of the 2022 Senior Notes and borrowings under the revolving credit facilities.

The gathering, transmission and storage and water services businesses are capital intensive, requiring significant investment to develop new facilities and to maintain and upgrade existing operations. 

The following represents the Company's material short-term and long-term cash requirements from contractual and other obligations as of December 31, 2023.

Contractual and other obligations exclude dividends associated with the Equitrans Midstream Preferred Shares.

Capital expenditures in 2024 are expected to be approximately $325 million to $395 million (including approximately $15 million attributable to the noncontrolling interest in Eureka Midstream). If the MVP project were to be completed in the second quarter of 2024 and at a total project cost ranging from approximately $7.57 billion to approximately $7.63 billion (excluding AFUDC), the Company expects it would make total capital contributions to the MVP Joint Venture in 2024 of approximately $540 million to $575 million primarily related to forward construction of the MVP project. Capital contributions payable to the MVP Joint Venture are accrued upon the issuance of a capital call by the MVP Joint Venture. The Company's short-term and long-term capital investments may vary significantly from period to period based on the available investment opportunities, the timing of the construction of the MVP and other projects, and maintenance needs. The Company expects to fund short-term and long-term capital expenditures and capital contributions primarily through cash on hand, cash generated from operations, available borrowings under its subsidiaries' credit facilities and its access to banking and capital markets.

See Note 9 and Note 15 to the consolidated financial statements for discussion of the Amended EQM Credit Facility and the 2021 Eureka Credit Facility.

The table below sets forth the credit ratings for EQM's debt instruments at December 31, 2023.

On August 29, 2023, Fitch affirmed EQM's credit rating on Rating Watch Positive. EQM's credit ratings are subject to revision or withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating. The Company cannot ensure that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a credit rating agency if, in its judgment, circumstances so warrant. If any credit rating agency downgrades or withdraws EQM's ratings, including for reasons relating to the MVP project (such as delays affecting the MVP project or increases in such project’s targeted costs), EQM’s leverage or credit ratings of the Company's customers, the Company's access to the capital markets could become more challenging, borrowing costs will likely increase, the Company may, depending on contractual provisions in effect at such time, be required to provide additional credit assurances (the amount of which may be substantial) and the potential pool of investors and funding sources may decrease. In order to be considered investment grade, a company must be rated Baa3 or higher by Moody's, BBB- or higher by S&P, or BBB- or higher by Fitch. All of EQM's credit ratings are considered non-investment grade.

From time to time, various legal and regulatory claims and proceedings are pending or threatened against the Company and its subsidiaries. While the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Company accrues legal and other direct costs related to loss contingencies when incurred. The Company establishes reserves whenever it believes it to be appropriate for pending matters. Furthermore, after consultation with counsel and considering the availability, if any, of insurance, the Company believes, although no assurance can be given, that the ultimate outcome of any matter currently pending against it or any of its consolidated subsidiaries as of the filing of this Annual Report on Form 10-K will not materially adversely affect its business, financial condition, results of operations, liquidity or ability to pay dividends to its shareholders.

See Note 14 to the consolidated financial statements for further discussion of the Company's commitments and contingencies.

On February 14, 2024, the Company paid cash dividends for the fourth quarter of 2023 of $0.15 per common share and $0.4873 per Equitrans Midstream Preferred Share to shareholders of record at the close of business on February 6, 2024.

For each quarter ending after March 31, 2024, the holders of the Equitrans Midstream Preferred Shares will receive quarterly dividends at a rate per annum equal to the sum of (i) three-month CME Term SOFR, administered by CME Group Benchmark Administration, Ltd., plus a tenor spread adjustment of 0.26161% per annum as of the relevant determination date in respect of the applicable quarter and (ii) 8.15%; provided that such rate per annum in respect of periods after March 31, 2024 will not be less than 10.50%. As such, the Company expects dividends paid to holders of the Equitrans Midstream Preferred Shares to be higher beginning in the third quarter of 2024.

Recently issued accounting standards relevant to the Company are described in Note 1 to the consolidated financial statements.

The Company's significant accounting policies are described in Note 1 to the consolidated financial statements, which have been prepared in accordance with GAAP. Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been included in the notes to the Company's consolidated financial statements. Preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts in the Company's consolidated financial statements and accompanying notes. The Company's critical accounting policies discussed below are considered critical due to the significant judgments and estimates used in the preparation of the Company's consolidated financial statements and the material impact on the results of operations or financial condition. Actual results could differ from those judgments and estimates.

Goodwill is the cost of an acquisition less the fair value of the identifiable net assets of the acquired business. Goodwill is evaluated for impairment at least annually or whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. When performing a quantitative assessment, the Company uses a combination of an income and market approach to estimate the fair value of its reporting units.

The Company believes that the accounting estimates related to impairments are "critical accounting estimates" because they require assumptions that are susceptible to change, including estimating fair value which requires considerable judgment. For example, in the case of goodwill, management’s estimate of a reporting unit’s future financial results is sensitive to changes in assumptions, such as changes in the Company's stock price, weighted-average cost of capital, terminal growth rates and industry multiples. When a quantitative assessment is performed, the Company uses estimates and assumptions in estimating its reporting units’ fair values that it believes are reasonable and appropriate at that time; however, different assumptions and estimates could materially affect the calculated fair value and the resulting conclusion of whether goodwill is impaired, which could materially affect the Company’s results of operations and financial position.

The Company’s investment in unconsolidated entity also requires considerable judgment to estimate fair value because the Company’s investment is not traded on an active market. When estimating the fair value of its equity method investment, the Company utilizes an income approach under which significant judgments and assumptions, including the discount rate and probability-weighted scenarios, are sensitive to change. Additionally, the Company's investment in unconsolidated entity is susceptible to impairment risk from adverse macroeconomic conditions and/or other adverse factors. Adverse developments could require that the Company modify assumptions reflected in the probability-weighted scenarios of discounted future net cash flows (including with respect to the probability of success prior to completion) utilized to estimate the fair value of its equity method investment in the MVP Joint Venture, which could result in an incremental other-than-temporary impairment of that investment. While macroeconomic factors in and of themselves may not be a direct indicator of impairment, should an impairment indicator be identified in the future, macroeconomic factors such as changes in interest rates could ultimately impact the size and scope of any potential impairment.

See Notes 1 and 7 to the consolidated financial statements for additional information.

and variable consideration. Fixed consideration primarily relates to firm reservation payments including MVCs and ARCs. Variable consideration is generally dependent on volumes and recognized in the period they occur. At each reporting date and, as circumstances or events warrant, management reviews and updates the assumptions utilized to estimate the total consideration for all contracts. The Company allocates the transaction price to each performance obligation based on the estimated relative standalone selling price. When applicable, the excess of consideration received over revenue recognized results in the deferral of those amounts until future periods based on a units of production or straight-line methodology as these methods appropriately match the consumption of services provided to the customer. The units of production methodology requires the use of production estimates that are uncertain and the use of judgment when developing estimates of future production volumes, thus impacting the rate of revenue recognition. Production estimates are monitored as circumstances and events warrant. Certain of the Company's gas gathering and water agreements have MVCs or ARCs. If a customer under such an agreement fails to meet its MVC or ARC for a specified period (thus not exercising all the contractual rights to gathering and water services within the specified period, herein referred to as “breakage”), it is obligated to pay a contractually determined fee based upon the shortfall between the actual volumes and the MVC or ARC for the period contained in the contract. When management determines it is probable that the customer will not exercise all or a portion of its remaining rights, the Company recognizes revenue associated with such breakage amount in proportion to the pattern of exercised rights within the respective MVC or ARC period.

Revenue related to services provided but not yet billed is estimated each month. These estimates are generally based on contract data, preliminary throughput and allocation measurements. Final amounts for the current month are billed and collected in the following month. See Note 4 to the consolidated financial statements for additional information.

The Company records an allowance for credit losses on a quarterly basis in order to estimate uncollectible receivables. The Company's current expected credit loss (CECL) methodology considers risks of collection based on a customer’s current credit status. The standard requires an entity to assess whether financial assets share similar risk characteristics and, if so, group such assets in a pool. Customer balances are aggregated for evaluation based on their credit risk rating, which takes into account changes in economic factors that impact a customer’s ability to meet its financial obligations. The Company's CECL methodology assigns a reserve, even if remote, to each customer based on credit risk and the reserve is evaluated on a quarterly basis. In order to calculate the appropriate allowance, the Company utilizes an estimated loss rate factor based on a customer's credit rating for receivables and a risk-adjusted reserve based on the receivable aging schedule in order to account for the receivables which may be at a greater risk of collection. Customer credit risk ratings are updated quarterly and management has enabled a risk-responsive approach to changes in customer and economic factors. While the Company has not historically experienced material losses on uncollected receivables, a decline in the market price for natural gas affecting producer activity combined with additional customers on the Company's systems may result in a greater exposure to potential losses than management's current estimates.

The Company believes that the accounting estimates related to revenue recognition are "critical accounting estimates" because estimated relative standalone selling prices and volumes are subject to change based on actual measurements. In addition, the Company believes that the accounting estimates related to the allowance for credit losses are "critical accounting estimates" because the underlying assumptions used for the allowance can change and the actual mix of customers and their ability to pay may vary significantly from management's estimates, which could affect the collectability of customer receivables. These accounting estimates could potentially have a material effect on the Company's results of operations and financial position.

The Company has federal and state of West Virginia net operating loss (NOL) carryforwards. The NOL carryforwards have no expiration, but utilization is limited to 80% of taxable income in the year of utilization. In addition to the NOL carryforwards, the Company has deferred tax assets and liabilities principally resulting from interest disallowance under Code Section 163(j) and investment in partnerships.

Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not (greater than 50%) that a tax benefit will not be realized. In evaluating the need for a valuation allowance, this requires significant judgment and management considers all available evidence, both positive and negative, including potential sources of taxable income, income available in carry-back periods, future reversals of taxable temporary differences, projections of taxable income and income from tax planning strategies. Positive evidence includes reversing temporary differences and projection of future profitability within the carry-forward period, including from tax planning strategies. Negative evidence includes historical pre-tax book losses.

Deferred tax assets for which no valuation allowance is recorded may not be realized, and changes in facts and circumstances may result in the establishment of a valuation allowance. Existing valuation allowances are re-examined under the same

standards of positive and negative evidence that apply to valuation allowance establishment. If it is determined that it is more likely than not that a deferred tax asset for which a valuation allowance is recorded will be realized, all or a portion of the valuation allowance may be released. Deferred tax assets and liabilities are also remeasured to reflect changes in underlying tax rates from tax law changes and any changes in uncertain tax benefits.

The Company believes that accounting estimates related to income taxes are "critical accounting estimates" because the Company must assess the likelihood that deferred tax assets will be recovered from future taxable income, and exercise judgment when evaluating whether or not a valuation allowance must be established on deferred tax assets. See Note 12 to the consolidated financial statements for additional information.

The Company is exposed to the credit risk of its customers, including its largest customer, EQT, including as a result of changes in customer credit ratings, liquidity and access to capital markets. In August 2023, Moody's upgraded EQT's public senior debt to an investment grade credit rating and as of December 31, 2023, EQT's public debt has investment grade credit ratings from S&P, Fitch and Moody's. On February 26, 2020, in connection with the execution of the EQT Global GGA, the Company and EQT entered into a letter agreement (the Credit Letter Agreement) pursuant to which, among other things, (a) the Company agreed to relieve certain credit posting requirements for EQT, in an amount up to approximately $250 million, under its commercial agreements with the Company, subject to EQT maintaining a minimum credit rating from two of three rating agencies of (i) Ba3 with Moody's, (ii) BB- with S&P and (iii) BB- with Fitch and (b) the Company agreed to use commercially reasonable good faith efforts to negotiate similar credit support arrangements for EQT in respect of its commitments to the MVP Joint Venture. In addition, EQT has guaranteed the payment obligations of certain of its subsidiaries, up to a maximum amount of $115 million, $131 million and $30 million related to gathering, transmission and water services, respectively, across all applicable contracts, for the benefit of the subsidiaries of the Company providing such services. See Note 13 to the consolidated financial statements in this Annual Report on Form 10-K, for further discussion of the Company's exposure to certain credit risks.

Price declines and sustained periods of low natural gas and NGL prices could have an adverse effect on the creditworthiness of the Company's customers and related ability to pay firm reservation fees under long-term contracts and/or affect, as discussed above, activity levels and, accordingly, volumetric-based fees, which could affect the Company’s results of operations, liquidity or financial position. Credit risk and related management is further discussed under “Credit Risk” in Part II, “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” of this Annual Report on Form 10-K.

Increases in natural gas prices do not necessarily result in corresponding increases to the production forecasts of the Company's customers. Even when natural gas prices have been commercially attractive, certain of the Company's customers maintained largely flat production forecasts in light of, among other things, the absence of incremental takeaway capacity from the Appalachian Basin and the Company's customers may still maintain flat or modest increases to production forecasts based on various factors, which could include regional takeaway capacity limitations, access to capital, investor expectations regarding free cash flow, a desire to reduce or refinance leverage or other factors.

Additionally, lower natural gas prices (including regionally), corporate capital allocation strategies or regional takeaway constraints, could cause producers to determine in the future that drilling activities in areas outside of the Company's current areas of operation are strategically more attractive to them.

While EQT has dedicated a substantial portion of its core acreage in southwestern Pennsylvania and West Virginia to the Company and has entered into long-term firm gathering and transmission contracts and contracts with MVCs on certain of the Company's systems, EQT may determine in the future that drilling or continuing to produce gas from existing wells in the Company's areas of operations is not economical above the amount to fulfill its required MVCs or otherwise strategically determine to curtail volumes on the Company's systems. Other than with respect to its MVCs and other firm commitments under existing contracts, EQT is under no contractual obligation to continue to develop its acreage dedicated to the Company. See also "Overview of the Company and Operations" in Part 1, "Item 1. Business" of this Annual Report on Form 10-K for a discussion of the EQT Global GGA.

The fair value of the Company’s derivative instruments is, in part, determined by estimates of the NYMEX Henry Hub natural gas forward price curve. A hypothetical 10% increase in NYMEX Henry Hub natural gas futures prices would increase the valuation of the Company’s derivative instruments by approximately $5.9 million, while a hypothetical 10% decrease in

To the Shareholders and the Board of Directors of Equitrans Midstream Corporation

We have audited the accompanying consolidated balance sheets of Equitrans Midstream Corporation (the Company) as of December 31, 2023 and 2022, the related statements of consolidated comprehensive income, cash flows and shareholders' equity and mezzanine equity for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 20, 2024 expressed an unqualified opinion thereon.

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2023 and 2022, the related statements of consolidated comprehensive income, cash flows and shareholders' equity and mezzanine equity for each of the three years in the period ended December 31, 2023, and the related notes and our report dated February 20, 2024 expressed an unqualified opinion thereon.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.